SUNCOR ENERGY INC

SUNCOR ENERGY INC.
ANNUAL INFORMATION FORM
March 3, 2008
ANNUAL INFORMATION FORM
TABLE OF CONTENTS
TABLE OF CONTENTS ................................................................................................................................ ii
GLOSSARY OF TERMS...............................................................................................................................iii
CONVERSION TABLE.................................................................................................................................vii
CURRENCY ................................................................................................................................................viii
FORWARD-LOOKING STATEMENTS.......................................................................................................viii
NON GAAP FINANCIAL MEASURES ......................................................................................................... ix
CORPORATE STRUCTURE ........................................................................................................................ 1
GENERAL DEVELOPMENT OF THE BUSINESS ....................................................................................... 2
NARRATIVE DESCRIPTION OF THE BUSINESS ...................................................................................... 7
NATURAL GAS (NG) .................................................................................................................................. 10
REFINING AND MARKETING (R&M) ........................................................................................................ 12
MATERIAL CONTRACTS........................................................................................................................... 18
RESERVES ESTIMATES ........................................................................................................................... 18
REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE.................................................................. 20
VOLUNTARY OIL SANDS RESERVES AND RESOURCES DISCLOSURE ............................................ 29
SUNCOR EMPLOYEES ............................................................................................................................. 31
RISK FACTORS.......................................................................................................................................... 32
SELECTED CONSOLIDATED FINANCIAL INFORMATION ..................................................................... 40
MANAGEMENT'S DISCUSSION AND ANALYSIS .................................................................................... 41
DESCRIPTION OF CAPITAL STRUCTURE .............................................................................................. 41
MARKET FOR OUR SECURITIES............................................................................................................. 42
DIRECTORS AND EXECUTIVE OFFICERS.............................................................................................. 43
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................................... 47
TRANSFER AGENT AND REGISTRAR..................................................................................................... 47
INTERESTS OF EXPERTS ........................................................................................................................ 48
FEES PAID TO AUDITORS........................................................................................................................ 48
RELIANCE ON EXEMPTIVE RELIEF ........................................................................................................ 50
LEGAL PROCEEDINGS ............................................................................................................................. 51
ADDITIONAL INFORMATION .................................................................................................................... 51
ii
GLOSSARY OF TERMS
In this Annual Information Form (AIF), references to "we", "our", "us", "Suncor" or the "company" include
Suncor Energy Inc., its subsidiaries, partnerships and joint venture investments unless the context
otherwise requires.
Barrel of Oil Equivalent (BOE)
Suncor converts natural gas to barrels of oil equivalent (BOE) at a 6 mcf:1 bbl ratio. BOEs may be
misleading, particularly if used in isolation. A BOE conversion ratio of 6:1 is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Best Estimate Resources
Is considered to be the best estimate of the quantity of resources that will actually be recovered. It is
equally likely that the actual remaining quantities recovered will be greater or less than the best estimate.
The best estimate of potentially recoverable volumes is generally prepared independent of the risks
associated with achieving commercial production
Bitumen/Heavy Crude Oil
A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons heavier than pentane,
which is not recoverable at a commercial rate in its naturally occurring viscous state through a well
without using enhanced recovery methods. When extracted, bitumen/heavy crude oil may be upgraded
into crude oil and other petroleum products.
Capacity
Maximum annual average output that may be achieved from a facility in ideal operating conditions in
accordance with current design specifications.
Coal Bed Methane
Natural gas produced from wells drilled into a coal formation.
Contingent Resources
Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or more contingencies.
Conventional Crude Oil
Crude oil produced through wells by standard industry recovery methods.
Conventional Natural Gas
Natural gas produced from all geological strata, excluding coal bed methane.
Crude Oil
Unrefined liquid hydrocarbons, excluding natural gas liquids.
iii
Developed Reserves
Developed reserves are those proved reserves that are expected to be recovered from existing wells and
installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when
compared to the cost of drilling a well) to put the reserves on production.
Development Costs
Includes all costs associated with moving reserves from other classes such as "proved undeveloped" and
"probable" to the "proved developed" class.
Downstream
This business segment manufactures, distributes and markets refined products from crude oil.
Dry Hole/Well
An exploration or development well determined, on an economic basis, to be incapable of producing
hydrocarbons that will be plugged, abandoned and reclaimed.
Feedstock
Purchases of components required in the production of refined product other than crude oil.
Finding Costs
Includes the cost of and investment in undeveloped land, geological and geophysical activities,
exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas
reserves.
Gross Production/Reserves
Suncor's working interest in production/reserves, as the case may be, before deducting Crown royalties,
freehold and overriding royalty interests.
Gross Wells/Land Holdings
Total number of wells or acres, as the case may be, in which Suncor has an interest.
Heavy Fuel Oil
Residue from refining of conventional crude oil that remains after lighter products such as gasoline,
petrochemicals and heating oils have been extracted. This product traditionally sells at less than the cost
of crude oil.
In-situ Oil
In-situ or "in place" refers to methods of extracting heavy crude oil from deep deposits of oil sands by
drilling with minimal disturbance of the ground cover.
Lifting Costs
Includes all expenses related to the operation and maintenance of producing or producible wells and
related facilities, natural gas plants and gathering systems.
iv
MD&A
Suncor's Management's Discussion and Analysis dated February 27, 2008, accompanying its audited
consolidated financial statements, notes thereto and auditor's report thereon, as at and for the three years
in the period ended December 31, 2007, which is incorporated by reference herein.
Natural Gas
Hydrocarbons that at atmospheric conditions of temperature and pressure are in a gaseous state.
Natural Gas Liquids
Hydrocarbon products recovered as liquids from raw natural gas by processing through extraction plants
or recovered from field separators, scrubbers or other gathering facilities. These liquids include the
hydrocarbon components ethane, propane, butane and pentane, or a combination thereof.
Net Production/Reserves
Suncor's undivided percentage interest in total production or total reserves, as the case may be, after
deducting Crown royalties and freehold and overriding royalty interests.
Net Wells/Land Holdings
Suncor's undivided percentage interest in the gross number of wells or gross number of acres, as the
case may be, after deducting interests of third parties.
Overburden
Material overlying oil sands that must be removed before mining. Consists of muskeg, glacial deposits
and sand.
Oil Sands
Oil sands are a naturally occurring mixture of water, sand, clay and bitumen, a very heavy crude oil.
Probable Reserves1
Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves. It is equally likely2 that the actual remaining quantities recovered will be greater or less than the
sum of the estimated proved plus probable reserves.
1
We are subject to Canadian disclosure rules in connection with the reporting of reserves. However, we have received
exemptive relief from Canadian securities administrators permitting us to report our reserves in accordance with U.S.
disclosure practices. Although U.S. companies do not disclose probable reserves for non-mining properties, we
voluntarily disclose probable reserves for our Firebag in-situ leases as we believe this information is useful to investors.
In addition, U.S. companies do not disclose resources but we believe this information is also useful to investors and
accordingly disclose "contingent resources" in accordance with National Instrument 51-101. See "RESERVES
ESTIMATES" on page 18 for a description of how our voluntary reserves disclosure differs from our U.S. required
disclosure.
2
In estimating our proved and probable reserves, our independent reserves evaluators, GLJ Petroleum Consultants Ltd.
(“GLJ”), have targeted the following levels of certainty: at least 90% probability that the quantities actually recovered will
equal or exceed the estimated proved reserves; and at least a 50% probability that the quantities actually recovered will
equal or exceed the sum of the estimated proved plus probable reserves. However, as our reserves have been prepared
using deterministic, rather than probabilistic methods, consistent with industry practice, GLJ’s estimates do not provide a
mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates
prepared using probabilistic or deterministic methods.
v
Proved oil and gas reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty2 to be recoverable in future
years from known reservoirs under assumed economic and operating conditions.
Reservoirs are considered proved if economic producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining
portions not yet drilled, but which may be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which may be produced economically through application of improved recovery techniques
(such as fluid injection) are included in the "proved" classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may become available from known
reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and
natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids,
that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
For a discussion of pricing assumptions see the tables under the headings "Required U.S. Oil and Gas
and Mining Disclosure – Proved Conventional Oil and Gas Reserves" and under "Voluntary Oil Sands
Reserves and Resources Disclosure - Oil Sands Mining and In-Situ Firebag Reserves Reconciliation".
Proved Producing Reserves
Proved producing reserves are those reserves that are expected to be recovered from completion
intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they
must have previously been on production, and the anticipated date of resumption of production must be
known.
Remaining Recoverable Resources
The sum of reserves and contingent resources.
Reservoir
Body of porous rock containing an accumulation of water, crude oil or natural gas.
Sour Synthetic Crude Oil
Crude oil produced from oil sands that requires only partial upgrading and contains a higher sulphur
content than sweet synthetic crude oil.
Sweet Synthetic Crude Oil
Crude oil produced from oil sands consisting of a blend of hydrocarbons resulting from thermal cracking
and purification of bitumen.
vi
Synthetic Crude Oil
Upgraded or partially upgraded crude oil recovered from oil sands including surface mineable oil sands
leases and in-situ oil sands/heavy oil leases.
Undeveloped Oil and Natural Gas Lands
Undeveloped lands are those on which wells have not been drilled or completed to a point that would
permit production of commercial quantities of crude oil and natural gas regardless of whether such
acreage contains proved reserves.
Upstream
These business segments include acquisition, exploration, development, production and marketing of
crude oil, natural gas and natural gas liquids; and for greater clarity include the production of synthetic
crude oil, bitumen and other oil products from oil sands as well as production using conventional
methods.
Utilization
The average use of capacity taking into consideration planned and unplanned outages and maintenance.
Wells
Development Well
A crude oil or natural gas well drilled in, or adjacent to, a reservoir known to be productive and expected
to produce in the future.
Drilled Well
A well that has been drilled and has a defined status (e.g. gas well, shut-in well, producing oil well,
producing gas well, suspended well or dry and abandoned well).
Exploratory Well
A well drilled in a territory without existing proved reserves, with the intention to discover commercial
reservoirs or deposits of crude oil and/or natural gas.
CONVERSION TABLE
1 cubic metre m3 = 6.29 barrels
1 cubic metre m3 (natural gas) = 35.49 cubic feet
1 cubic metre m3 (overburden) = 1.31 cubic yards
1 tonne = 0.984 tons (long)
1 tonne = 1.102 tons (short)
1 kilometre = 0.62 miles
1 hectare = 2.5 acres
Notes:
(1)
Conversion using the above factors on rounded numbers appearing in this Annual Information Form may produce small
differences from reported amounts.
(2)
Some information in this Annual Information Form is set forth in metric units and some in imperial units.
vii
CURRENCY
All references in this Annual Information Form to dollar amounts are in Canadian dollars unless otherwise
indicated.
FORWARD-LOOKING STATEMENTS
This Annual Information Form contains certain forward-looking statements that are based on our current
expectations, estimates, projections and assumptions that were made by the company in light of its
experience, and its perception of historical trends.
All statements that address expectations or projections about the future, including statements about our
strategy for growth, expected future expenditures, commodity prices, costs, schedules, production
volumes, operating and financial results and expected impact of future commitments, are forward-looking
statements. Some of the forward-looking statements may be identified by words like "expects,"
"anticipates," "estimates," "plans,” "scheduled,” “intends,” “may,” "believes," “projects,” "indicates,"
"could," “focus,” “vision,” "goal," “proposed,” "target," "objective," "continue" and similar expressions.
These statements are not guarantees of future performance and involve a number of risks and
uncertainties, some that are similar to other oil and gas companies and some that are unique to our
experience. Our actual results may differ materially from those expressed or implied by our forwardlooking statements and you are cautioned not to place undue reliance on them.
The risks, uncertainties and other factors, many of which are beyond our control, that could influence
actual results include but are not limited to: changes in the general economic, market and business
conditions; fluctuations in supply and demand for our products; commodity prices, interest rates and
currency exchange rates; our ability to respond to changing markets, and to receive timely regulatory
approvals; the successful and timely implementation of capital projects including growth projects (for
example, the Voyageur project, including our Firebag in-situ development) and regulatory projects (for
example, the emissions reduction modifications at our Firebag in-situ development); the accuracy of cost
estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior
to commencement of conception of the detailed engineering needed to reduce the margin of error or level
of accuracy; the integrity and reliability of our capital assets; the cumulative impact of other resource
development; the cost of compliance with existing and future environmental laws; the accuracy of
Suncor’s reserve, resource and future production estimates and our success at exploration and
development drilling and related activities; the maintenance of satisfactory relationships with unions,
employee associations and joint venture partners; competitive actions of other companies, including
increased competition from other oil and gas companies and from companies that provide alternative
sources of energy; labour and material shortages; uncertainties resulting from potential delays or
changes in plans with respect to projects or capital expenditures; actions by governmental authorities
including the imposition of taxes or changes to fees and royalties; changes in environmental and other
regulations (for example, the Government of Alberta’s current review of the unintended consequences of
the proposed Crown Royalty regime, and the Government of Canada’s current review of greenhouse gas
emission regulations); the ability and willingness of parties with whom we have material relationships to
perform their obligations to us; and the occurrence of unexpected events such as fires, blowouts, freezeups, equipment failures and other similar events affecting us or other parties whose operations or assets
directly or indirectly affect us. These important factors are not exhaustive.
Many of these risk factors and other specific risks and uncertainties are discussed in further detail
throughout this Annual Information Form and in our MD&A, incorporated by reference herein. Readers
are also referred to the risk factors described in other documents we file from time to time with securities
regulatory authorities. Copies of these documents are available without charge from Suncor at 112 – 4th
Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by email request to
[email protected] or by referring to SEDAR at www.sedar.com or by referring to EDGAR at www.sec.gov.
Information contained in or otherwise accessible through our website does not form a part of this AIF, and
is not incorporated into the AIF by reference.
viii
References herein to our 2007 Consolidated Financial Statements mean Suncor's audited consolidated
financial statements prepared in accordance with Canadian generally accepted accounting principles
(“GAAP”), the notes thereto and the auditor's report thereon, as at and for the three years in the period
ended December 31, 2007.
NON GAAP FINANCIAL MEASURES
Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, cash flow
from operations, Oil Sands cash and total operating costs per barrel and Return on Capital Employed
(ROCE), are described and reconciled in the "Non GAAP Financial Measures" section of our MD&A,
incorporated by reference herein.
ix
CORPORATE STRUCTURE
Name and Incorporation
Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada
Business Corporations Act on August 22, 1979, of Sun Oil Company Limited, incorporated in 1923 and
Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, we amalgamated with a
wholly-owned subsidiary under the Canada Business Corporations Act. We amended our articles in 1995
to move our registered office from Toronto, Ontario, to Calgary, Alberta, and again in April 1997, to adopt
our current name, "Suncor Energy Inc.". In April 1997, May 2000, and May 2002, we amended our
articles to divide our issued and outstanding shares on a two-for-one basis.
Our registered and principal office is located at 112 - 4th Avenue, S.W. Calgary, Alberta, T2P 2V5.
Intercorporate Relationships
We have four principal subsidiaries and partnerships.
Suncor Energy Oil Sands Limited Partnership is an Alberta limited partnership that is indirectly wholly
owned by Suncor Energy Inc. Effective February 1, 2005, Suncor Energy Inc., as general partner, and
one of its wholly-owned subsidiaries, as a limited partner, formed the Suncor Energy Oil Sands Limited
Partnership. At this time the partnership held certain net profits interests related to our oil sands business
and natural gas business. Effective January 1, 2006, Suncor Energy Inc. contributed, subject to certain
exceptions, its oil sands assets to the partnership. This internal reorganization had no effect on
operations or on our consolidated net earnings.
Suncor Energy Products Inc. (formerly Sunoco Inc.) is an Ontario corporation that is wholly-owned by
Suncor Energy Inc. This company refines and markets petroleum products and petrochemicals directly
and indirectly through subsidiaries and joint ventures. We operate a retail business in Canada under the
Sunoco brand through this subsidiary. We are unrelated to Sunoco, Inc. (formerly known as Sun
Company, Inc.), headquartered in Philadelphia, Pennsylvania.
Suncor Energy Marketing Inc., wholly-owned by Suncor Energy Products Inc., is incorporated under the
laws of Alberta. This company markets, mainly to customers in Canada and the United States, the crude
oil, diesel fuel, bitumen and byproducts such as petroleum coke, sulphur and gypsum, produced by our
Oil Sands business. Through this subsidiary we also administer Suncor’s energy trading activities,
market certain third party products, and procure crude oil feedstocks and natural gas for our downstream
business. This subsidiary markets certain natural gas volumes produced by, and purchased from, our
Natural Gas business unit. Suncor Energy Marketing Inc. also has a petrochemical marketing division
that holds a 50% interest in Sun Petrochemicals Company, a petrochemical products joint venture.
Suncor Energy (U.S.A.) Inc., indirectly wholly-owned by Suncor Energy Inc., is incorporated under the
laws of Delaware. Through this U.S. subsidiary, headquartered in Denver, Colorado, we refine crude oil
at our refinery in Commerce City, Colorado, near Denver, into a broad range of petroleum products, and
market our refined products to industrial, wholesale and commercial customers principally in Colorado
and to retail customers in Colorado through Phillips 66 ® - branded sites. We also transport crude oil on
our wholly owned pipelines in Wyoming and Colorado.
We also have a number of other subsidiary companies. However, the total assets of such subsidiaries
and partnerships combined, and their total sales and operating revenues, do not constitute more than 20
per cent of the consolidated assets, or consolidated sales and operating revenues, respectively, of
Suncor.
1
GENERAL DEVELOPMENT OF THE BUSINESS
Overview
Suncor is an integrated energy company, with corporate headquarters in Calgary, Alberta, Canada. We
are strategically focused on developing one of the world’s largest petroleum resource basins – Canada’s
Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and
natural gas, transport and refine crude oil and market petroleum and petrochemical products.
Periodically, we also market third party petroleum products. We also carry on energy trading activities
focused principally on buying and selling futures contracts and other derivative instruments based on the
commodities we produce.
We have three principal operating businesses:
Our Oil Sands business, based near Fort McMurray, Alberta, recovers bitumen, primarily through oil
sands mining and in-situ development, and upgrades it into refinery feedstock, diesel fuel and byproducts. Bitumen feedstock is also occasionally supplemented by third party suppliers.
Our Natural Gas business, based in Calgary, Alberta, explores for, acquires, develops and produces
natural gas and natural gas liquids from reserves in Western Alberta and Northeastern British Columbia.
The sale of natural gas production provides a natural price hedge for natural gas purchased for internal
consumption. In addition, our indirectly wholly-owned U.S. subsidiary, Suncor Energy (Natural Gas)
America Inc., acquires land and explores for coal bed methane in the United States.
Our third business, Refining and Marketing, refines crude oil at Suncor’s refineries in Sarnia, Ontario, and
Commerce City, Colorado, into a broad range of petroleum, petrochemical and biofuel products. These
products are then marketed to industrial, wholesale and commercial customers principally in Ontario,
Quebec and Colorado. In Ontario, our retail businesses are managed through Sunoco-branded and joint
venture operated retail networks, and in Colorado our retail businesses are managed through Phillips 66
® - branded sites. We also transport crude oil on our wholly owned pipelines in Wyoming and Colorado,
and engage in third party energy marketing and trading activities through this business.
For financial reporting purposes, we also report financial data for activities not directly attributable to an
operating business under the results of Suncor's "Corporate" segment. This includes the activity of our
self-insurance entity, as well as investments in wind energy.
In 2007, we produced approximately 271,400 boe per day, comprised of 238,700 barrels per day (bpd) of
crude oil and natural gas liquids and 196 million cubic feet per day (mmcf/d) of natural gas. In 2006, the
most recent period with published results, we were the second largest crude oil and natural gas liquids
producer in Canada (approximately 10%3 of Canada's crude oil production in 2006) and the 16th largest
natural gas producer in Canada.4
In 2007, our Refining and Marketing business sold approximately 210,700 bpd (2006 – 185,600 bpd) or
33,500 m3 per day (2006 – 29,500 m3 per day) of refined products, mainly in Ontario and Colorado, but
also in other states throughout the United States and in Europe.
3
4
CAPP Crude Oil Report – Table 1 Canadian Crude Oil Production Forecast
Oilweek – July 2007, Top 100 Oil and Gas Producers
2
Three-Year History
Oil Sands (OS)
Over the past three years we have continued to advance our multi-phased growth strategy to increase
production capacity to 550,000 bpd in 2012. Key milestones and significant events that have affected our
Oil Sands business during this time period include the following:
•
Oil Sands Fire – A fire on January 4, 2005 caused significant damage to one of our two upgraders,
reducing upgraded crude oil production capacity from 225,000 bpd to about 122,000 bpd for the first
nine months of 2005. Repair and maintenance work to restore the facility was completed in
September 2005. Our property loss and business interruption insurance policies substantially
mitigated the financial impact of the fire, and were fully settled in 2006.
•
New Vacuum Unit and Debottleneck – During the fourth quarter of 2005, we increased our production
capacity to 260,000 bpd through the completion of a new vacuum unit. In addition, we also
completed a debottleneck of our Steepbank mine operation.
•
Firebag Stage 2 – Firebag Stage 2 commenced commercial operations in the first quarter of 2006,
furthering our plans to increase bitumen supply.
•
Royalties – In November 2006, we exercised our option, under our royalty agreement with the
Government of Alberta (the "Crown Agreement"), to transition our base oil sands mining operations
and associated upgrading from a royalty assessed on upgraded product values to a bitumen-based
royalty starting on January 1, 2009.
•
Voyageur South Mine Extension – In July 2007, Suncor filed a regulatory application for the Voyageur
South mine extension. Bitumen produced at the proposed project is expected to provide additional
feedstock flexibility.
•
Operating Permit – We were issued a new 10-year operating approval in connection with our Oil
Sands business in August 2007.
•
Firebag Cogeneration – A capital project expanding Firebag Stages 1 and 2 in conjunction with the
addition of a cogeneration facility was completed in 2007.
•
Regulatory Requirements
•
o
In September 2007, high emissions at our in-situ operations resulted in orders being issued
by both Alberta Environment and the Alberta Energy and Utilities Board. Until regulators can
be assured emissions are stable at compliant levels, production at the in-situ operation has
been capped at approximately 42,000 bpd.
o
In December 2007, high emissions at our base plant resulted in an order being issued by
Alberta Environment. Emissions at the oil sands plant exceeded air quality standards, and
accordingly we are upgrading our emission control equipment and reducing discharges to the
tailings ponds. In addition, we have introduced processing changes and are undertaking a
more comprehensive monitoring program.
Progress on Growth Projects – At December 31, 2007, the addition of a new set of cokers to our
upgrading complex was approximately 95% complete. This expansion is expected to increase
production capacity to 350,000 bpd, with construction completion targeted in the second quarter of
2008 and ramp-up to full capacity expected in the fourth quarter. Other work included construction of
a naphtha unit (which is intended enhance product mix) which was approximately 20% complete at
year-end, and the Steepbank extraction plant which was approximately 25% complete at year-end.
For further discussion of our significant capital projects, see page 19 of our MD&A.
3
The following changes to our Oil Sands business have occurred, or are expected to occur in 2008:
•
Royalty Amending Agreement – In January 2008, we entered into the Suncor Royalty Amending
Agreement with the government of Alberta, which modifies the rates under the Generic Regime
which would otherwise apply to our base mining operations, assuming the government enacts
their proposed framework. Under this agreement, prior to January 1, 2010, we would expect to
pay a royalty in respect of our base operations of 25% of the difference between a project's
annual gross revenues net of related transportation costs, less allowable costs including
allowable capital expenditures (R-C), and from January 1, 2010 through to January 1, 2016, we
would expect to pay royalties in accordance with the rates in the Generic Regime, subject to a
cap of 30% of R-C. (See page 19 of our MD&A for more information.)
•
Voyageur Growth Plan – In January 2008, Suncor’s Board of Directors approved a $20.6 billion
investment that is expected to boost crude oil production capacity at the company’s oil sands
operation by 200,000 bpd, bringing the total capacity to 550,000 bpd in 2012. The expansion
plans include constructing four additional stages of in-situ bitumen production, a new upgrader
(Suncor’s third) to convert that bitumen into higher-value crude oil, and various infrastructure and
utilities.
•
Petro-Canada Agreement – Incremental bitumen to feed the expanded Oil Sands operation is
expected to be partially obtained starting in 2008 under a processing agreement between Suncor
and Petro-Canada. Under the terms of the agreement, we will process a minimum of 27,000 bpd
of Petro-Canada bitumen on a fee-for-service basis. Petro-Canada retains ownership of the
bitumen and resulting sour crude oil production of about 22,000 bpd. In addition, Suncor has
agreed to sell an additional 26,000 bpd of our proprietary sour crude oil production to PetroCanada. Both the processing and sales components of the agreement are for a minimum 10year term.
Natural Gas (NG)
Key milestones and significant events that have affected our Natural Gas business during the past three
years include the following:
•
Divestment of non-core properties – In 2005 we disposed of non-core properties for proceeds of
$21 million.
•
Simonette Gas Plant – In December 2005, we, along with our partner, completed a plant capacity
expansion and a new pipeline to connect the Simonette plant with volumes produced from the
Cabin Creek and Solomon fields in the Alberta Foothills. We have a 37.5% ownership interest
and continue to operate the Simonette gas plant.
•
South Rosevear Gas Plant – In January 2006, we disposed of 15% of the total interest in the
South Rosevear gas plant for proceeds of $12 million. We currently retain a 60.4% interest and
continue to operate the gas plant.
•
Acquisition – In March 2007, we acquired developed and undeveloped lands in British Columbia
for approximately $160 million.
Refining and Marketing (R&M)
Consistent with the company’s organizational restructuring during the first quarter of 2007, results from
our Canadian and U.S. downstream marketing and refining operations have been combined into a single
business segment – Refining and Marketing. Key milestones and significant events that have affected
our Refining and Marketing business during the past three years include the following:
4
•
Valero Acquisition – On May 31, 2005 we acquired a refinery from Valero Energy Corporation
(“Valero”) in the Denver area adjacent to our existing refinery. The 30,000 bpd Valero refinery
was purchased for $37 million (US$30 million) plus working capital and associated oil and product
inventory adjustments, for a total acquisition cost of $62 million (US$50 million). The refinery was
acquired by purchasing all of the issued and outstanding stock of Valero’s indirect wholly-owned
subsidiary, Colorado Refining Company (“CRC”). CRC was subsequently merged into Suncor
Energy (USA) Inc. effective August 1, 2005. This facility was integrated with our existing U.S.
refinery. Our current combined refining capacity is approximately 90,000 bpd in the U.S.
•
Reduced Refinery Air Emissions – In connection with the acquisition of a 60,000 bpd refinery
from ConocoPhillips on August 1, 2003, we assumed obligations at the refinery pursuant to a
Consent Decree with the United States Environmental Protection Agency to reduce air emissions.
These obligations were met during a planned maintenance shutdown in 2006 for a total cost of
approximately $60 million (approximately US$50 million).
•
Diesel Desulphurization and Oil Sands Integration – In July 2006, the Commerce City refinery
completed its diesel desulphurization and oil sands integration project at a total cost of
approximately $530 million (US$435 million). The completion of the project allows the refinery to
produce ultra low sulphur diesel to meet requirements of fuels desulphurization legislation, and
enable the refinery to process up to 15,000 bpd of oil sands sour crude oil. In addition, the
modifications increased the refinery’s ability to process a broader slate of synthetic crude oil.
•
Ethanol Plant – In July 2006, we completed our St. Clair ethanol facility on time and on budget,
for a final cost of $112 million, and with a production capacity of 200 million litres per year. The
ethanol produced is primarily blended into our Sunoco-branded fuels and fuels sold through our
joint venture operated networks. Natural Resources Canada contributed $22 million towards this
project through their Ethanol Expansion Program. This contribution of $22 million includes a
repayment obligation and we have already repaid $2 million to date.
•
Diesel Desulphurization and Oil Sands Integration – In November 2007, Suncor completed the
final phase of a three year $950 million project at the Sarnia refinery. A 120-day shutdown to
complete the tie-ins was the last step in the multi-phased project. The project increased the
amount of oil sands crude oil the refinery can upgrade, improved the facility’s environmental
performance, and commencing in 2006 enabled the production of ultra low sulphur diesel fuel.
Other
Renewable Energy
In addition to renewable energy investments in ethanol production through our Refining and Marketing
segment, Suncor also invests in renewable wind power. Suncor is a partner in four wind power projects,
including two projects commissioned in the past three years.
In November 2006, we, along with our joint venture partners, Enbridge Income Fund and Acciona Wind
Energy Canada Inc., officially opened a 30-megawatt wind power project near Taber, Alberta called the
Chin Chute Wind Power Project. The project includes 20 wind turbines with the capacity to produce
enough zero-emission electricity to offset the equivalent of approximately 102,000 tonnes of carbon
dioxide per year.
In September 2007, we, along with our joint venture partner Acciona Wind Energy Canada Inc, officially
opened a 76-megawatt wind power plant near Ripley, Ontario. The $176 million Ripley Wind Power
Project consists of 38 wind turbines, a 27-km transmission line and two electrical substations. The project
is expected to displace at least 66,000 tonnes of carbon dioxide per year.
5
Other Transactions
Throughout 2005, $40 million was received for the provision of training services associated with the sale
of certain proprietary technology in 2004. Amounts are being recognized into income over the term of the
sale agreement.
6
NARRATIVE DESCRIPTION OF THE BUSINESS
OIL SANDS (OS)
Suncor produces a variety of refinery feedstock, diesel fuel and by-products by developing the Athabasca
oil sands in northeastern Alberta and upgrading the bitumen extracted at our plant near Fort McMurray,
Alberta. Our Oil Sands operations, accounting for virtually all of our conventional and synthetic crude oil
production in 2007, represent a significant portion of our 2007 capital employed5 (65%), cash flow from
operations5 (79%) and net earnings (87%). These percentages have been determined excluding the
corporate and eliminations segment information.
Operations
Our integrated Oil Sands business involves four operations located north of Fort McMurray, Alberta.
1) Bitumen is supplied from a combination of a mining operation using trucks and shovels, an in-situ
operation and third party bitumen supply.
2) Extraction facilities recover the bitumen from the oil sands ore that is mined. Since late 2005,
bitumen from Firebag is being upgraded, with only a small portion of production being strategically
sold directly into the market.
3) Heavy oil upgrading converts bitumen into crude oil products.
4) Utilities for the operation (water, steam and electricity) are generated through facilities on site, some
of which are owned and operated by Suncor, and others which are owned and operated by third
parties.
Mining/Extraction - The first step of the open pit mining operation is to remove the overburden with trucks
and shovels to access the oil sands - a mixture of sand, clay and bitumen. Oil sands ore is then
excavated and transported to a sizing plant followed by an ore preparation plant. Here, the oil sands ore
is mixed into a hot water slurry and pumped through hydrotransport pipelines to extraction plants on the
east and west sides of the Athabasca River. In extraction, bitumen is extracted from the oil sands ore
using a hot water process. After the final removal of impurities and minerals, naphtha is added to dilute
the bitumen to facilitate transportation to upgrading.
In-situ - Our in-situ operation uses an extraction technology called Steam Assisted Gravity Drainage
(“SAGD”) to extract bitumen from oil sands deposits that are too deep to be mined economically. The first
step of the SAGD process is to drill a pair of horizontal wells with one well located above the other.
Steam produced by on-site steam generation facilities is injected through the top well into the oil sands.
Heated bitumen and condensed steam drain into the bottom well and flow up the well to the surface. The
bitumen is pumped to our oil/water separation facilities where the water is removed from the bitumen,
treated, and recycled into the steam generation facilities. For current stages of in-situ development,
naphtha is added to dilute the bitumen to facilitate transportation to upgrading. Future stages propose to
use a heated pipeline instead of naphtha dilution for transport.
Upgrading - After the diluted bitumen is transferred to the upgrading plant, the naphtha is removed and
recycled to be used again as diluent. The bitumen from both SAGD and mining is upgraded through a
coking and distillation process. The upgraded product, referred to as sour synthetic crude oil, is either
sold directly to customers as sour synthetic crude oil or is further upgraded into sweet synthetic crude oil
by removing the sulphur and nitrogen using a hydrogen treating process. Four separate streams of
refined crude oil are produced: diesel, naphtha, kerosene and gas oil.
5
Refer to "Non GAAP Financial Measures" on page ix of this AIF.
7
We continue to explore and develop improved and alternative technologies to facilitate increased
efficiency and processing within our operations. For example, based on the results of testing performed
during the past two years, we plan to utilize new mining technology and processes in our future mine
development plans. This technology is incorporated in the July 2007 regulatory application for the
planned Voyageur South Mine extension.
While there is virtually no finding cost associated with synthetic crude oil, the delineation of the resource
and development and expansion of production entail significant capital outlays. For the same reason, the
costs associated with synthetic crude oil production are largely fixed in the short term, and as a result,
operating costs per unit are largely dependent on levels of production. Natural gas is used or consumed
in the production of synthetic crude oil, particularly in SAGD production at our Firebag operations, and
accordingly natural gas prices are a key variable component of synthetic crude oil production costs.
In the normal course of our operations we regularly complete planned maintenance shutdowns of our Oil
Sands facilities. These shutdowns are scheduled, and provide both preventative maintenance and capital
replacement which are expected to improve our operational efficiency. In July 2007 a scheduled
maintenance shutdown of Upgrader 2 occurred to facilitate the tie-in of new coker units, an important
milestone in the capital expansion project to increase Oil Sands production capacity to 350,000 bpd in the
second half of 2008. A 30-day planned shutdown of Upgrader 1 is expected to occur in 2008.
Principal Products
Sales of light sweet synthetic crude oil and diesel represented 59% of Oil Sands consolidated operating
revenues in 2007, compared to 53% in 2006. The other significant component of our revenues were light
sour synthetic crude oil and bitumen sales of 38% (2006 – 43%). Set forth below is information on daily
sales volumes and the corresponding percentage of Oil Sands consolidated operating revenues by
product for each of the last two years.
Product:
2007
(thousands
of barrels per
day)
Light sweet crude oil / diesel
Light sour crude oil / bitumen
Total
126.7
108.0
234.7
2006
(% of Oil
Sands
consolidated
revenues)
59
38
(thousands
of barrels per
day)
138.7
124.4
263.1
(% of Oil
Sands
consolidated
revenues)
53
43
We anticipate that approximately 47% of Oil Sands sales in 2008 will be light sweet synthetic crude and
diesel products.
Principal Markets
We market our crude oil product blends principally to customers in Canada and the United States, and
periodically to offshore markets.
Transportation
We own and operate a pipeline that transports synthetic crude oil from Fort McMurray, Alberta to
Edmonton, Alberta. The pipeline has a capacity of approximately 110,000 bpd.
Our Oil Sands business unit entered into a transportation service agreement with a subsidiary of Enbridge
Inc. for a term that commenced in 1999 and extends to 2028. Under the agreement, our current pipeline
capacity for the transport of synthetic crude oil and diluted bitumen from Fort McMurray, Alberta to
Hardisty, Alberta is 170,000 bpd. In addition, in 2008 we committed to an additional 12,000 bpd that
underpins current expansion plans for the pipeline.
8
In 2005, Suncor entered into a binding memorandum of understanding with Enbridge Pipelines
(Athabasca) Inc, Petro-Canada, Total E&P Canada Limited, and ConocoPhillips Surmont Partnership for
the transportation of crude oil, on a proposed new pipeline running from Cheecham, Alberta to Edmonton,
Alberta. The expected in-service date of the line is currently targeted for July 1, 2008, with a 25 year
term. Initial line capacity is expected to be 350,000 bpd with potential expansion of capacity to 600,000
bpd with the construction of additional pumping facilities. Our initial line commitment is 30,000 bpd. It is
expected that the pipeline will provide an enhanced ability to access new markets on the West coast and
offshore.
Suncor has entered into long term service agreements with affiliates of TransCanada Corporation for
transportation of crude oil on the Keystone pipeline. The agreements will provide for pipeline
transportation of our crude oil from Hardisty, Alberta to both Patoka, Illinois and Cushing, Oklahoma.
Transportation of crude oil on the Keystone pipeline is targeted to commence in 2009.
We continue to evaluate additional pipeline agreements to support our expected production capacity of
550,000 bpd in 2012.
Periodically, we also enter into strategic short term cargo transport agreements to ship synthetic crude oil
to the United States Gulf Coast. These agreements have a term of less than one year, and are specific to
individual shipments.
We have a 20 year agreement with TransCanada Pipeline Ventures Limited Partnership to provide us
with firm capacity on a natural gas pipeline that came into service in 1999. The natural gas pipeline ships
natural gas to our Oil Sands facility.
We also transport natural gas to our Oil Sands operations on the company-owned and operated Albersun
pipeline, constructed in 1968. It extends approximately 300 kilometres south of the plant and connects
with TransCanada Pipeline’s Alberta intra-provincial pipeline system. The Albersun pipeline has the
capacity to move in excess of 100 mmcf/day of natural gas. We arrange for natural gas supply and
control most of the natural gas on the system under delivery based contracts. The pipeline moves natural
gas both north and south for us and other shippers.
Our Oil Sands mining facilities are readily accessible by public road. Our Firebag in-situ facilities are
currently accessible by private road. We anticipate termination of such access in 2010, and are currently
evaluating alternative means of access.
Competitive Conditions
Competitive conditions affecting Oil Sands are described under the heading "Competition" in the "Risk
Factors" section of this Annual Information Form.
Seasonal Impacts
Severe winter climatic conditions at Oil Sands can cause reduced production and, in some situations, can
result in higher costs.
Sales of Synthetic Crude Oil and Diesel
Aside from on site fuel use, all of Oil Sands’ production is sold to, and subsequently marketed by, Suncor
Energy Marketing Inc. Primary markets for our crude oil products include refining operations in Alberta,
Ontario, the U.S. Midwest and the U.S. Rocky Mountain region. Diesel products are sold primarily in
Western Canada.
In 1997, we entered into a long-term agreement with Flint Hills Resources LLC ("Flint Hills") to supply
Flint Hills with up to 30,000 bpd (approximately 13% of our average 2007 total production (2006 – 11%))
of sour crude from the Oil Sands operation. We began shipping the crude to Flint Hills at Hardisty,
Alberta (from which Flint Hills ships the product to its refinery in Minnesota) on January 1, 1999. The
9
initial term of the agreement extends to January 1, 2009, with month to month evergreen terms thereafter,
subject to termination on twenty-four months notice by either party. Neither party has provided notice of
termination at this time.
Under a long term sales agreement with Consumers Co-operative Refineries Limited ("CCRL") we supply
CCRL with 20,000 bpd of sour crude oil production. In 2005, we signed another contract with CCRL for
an additional 12,000 bpd of sour crude oil. Prices for sour crude oil under both of these agreements are
set at agreed differentials to market benchmarks. Both CCRL agreements extend through to 2011, with
renewal options that could extend out to 2018 and beyond. Both agreements continue until terminated by
either party with twenty-four months notice. Neither party has provided notice of termination at this time.
In 2001, we announced an agreement with Petro-Canada to supply up to 30,000 bpd of diluent to dilute
bitumen produced by Petro-Canada. Deliveries under the contract are expected to end when the bitumen
processing and sour crude oil supply agreement with Petro-Canada, described below, takes effect no
later than January 1, 2009. Under the agreement, we will process a minimum of 27,000 bpd of PetroCanada bitumen on a fee for service basis. Petro-Canada will retain ownership of the bitumen and
resulting sour crude oil production of about 22,000 bpd. In addition, we will sell an additional 26,000 bpd
of our proprietary sour crude oil production to Petro-Canada. Both the processing and sales components
of the agreement are for a minimum 10-year term.
There were no customers that represented 10% or more of our consolidated revenues in 2007, 2006, or
2005.
A portion of our Oil Sands production is used in our Sarnia and Commerce City refining operations.
During 2007, the Sarnia refinery processed approximately 7% (2006 - 8%) of Oil Sands crude oil
production and the Commerce City refinery processed approximately 6% (2006 – 3%) of Oil Sands crude
oil production.
Environmental Compliance
For a discussion of environmental risks at our Oil Sands operations, refer to the "Legal and Regulatory
Risks" outlined in the "Risk Factors" section of this Annual Information Form, as well as the "Asset
Retirement Obligations" section under "Critical Accounting Estimates" in the "Suncor Overview and
Strategic Priorities" section of our MD&A.
NATURAL GAS (NG)
Our Natural Gas business, based in Calgary, Alberta, explores for, develops and produces conventional
natural gas and natural gas liquids in Western Canada, supplying markets throughout North America.
The sale of NG’s production provides a natural price hedge for natural gas purchased for internal
consumption.
In 2007, natural gas and natural gas liquids accounted for approximately 98% of the NG business unit’s
production (2006 – 97%).
NG’s exploration program is focused on multiple geological zones in three core asset areas: Northern
(northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast
British Columbia) and Central Alberta.
10
Marketing, Pipeline and Other Operations
We operate natural gas processing plants at South Rosevear, Pine Creek, Boundary Lake South,
Progress and Simonette with a total design capacity of approximately 315 mmcf/d. Our capacity interest
in these gas processing plants is approximately 135 mmcf/d. We also have varying undivided percentage
interests in natural gas processing plants operated by other companies and processing agreements in
facilities where we do not hold an ownership interest.
Approximately 87% of our natural gas production is sold to Suncor Energy Marketing Inc. and then
marketed under direct sales arrangements to customers in Alberta, British Columbia, Eastern Canada,
and the United States. Contracts for these direct sales arrangements are of varied terms, with a majority
having terms of one year or less, and incorporate pricing which is either fixed over the term of the contract
or determined on a monthly basis in relation to a specified market reference price. Under these contracts,
we are responsible for transportation arrangements to the point of sale.
Approximately 13% of our natural gas production is sold under existing contracts to aggregators ("system
sales"). Proceeds received by producers under these sales arrangements are determined on a netback
basis, whereby each producer receives revenue equal to its proportionate share of sales less regulated
transportation charges and a marketing fee. Most of our system sales volumes are contracted to Cargill
Gas Marketing Ltd. (formerly TransCanada Gas Services) and Pan-Alberta Gas. These companies resell
this natural gas primarily to eastern Canadian and Midwest and Eastern United States markets.
To provide exposure to the Pacific Northwest and California markets, we have a long-term gas pipeline
transportation contract on the National Energy Group Transmission Pipeline (formerly Pacific Gas
Transmission).
We do not typically enter long-term supply arrangements for our conventional crude oil production.
Instead, our conventional crude oil production is generally sold under spot contracts or under contracts
that can be terminated on relatively short notice. Our conventional crude oil production is shipped on
pipelines operated by independent pipeline companies. The NG business currently has no pipeline
commitments related to the shipment of crude oil.
Principal Products
Sales of natural gas represented 88% (2006 – 90%) of NG’s consolidated operating revenues in 2007,
with the remaining 12% (2006 – 10%) comprised of sales of natural gas liquids and crude oil. Set forth
below is information on daily sales volumes and the corresponding percentage of NG’s consolidated
operating revenues by product for the last two years.
Product:
Natural gas
Crude Oil and Natural gas liquids
Total
2007
(Millions of
cubic feet
equivalent
per day)
196
19
215
2006
(% of NG
consolidated
revenues)
88
12
(thousands
of barrels of
oil equivalent
per day)
191
18
209
(% of NG
consolidated
revenues)
90
10
Competitive Conditions
Competitive conditions affecting NG are described under "Competition" in the "Risk Factors" section of
this Annual Information Form.
11
Seasonal Impacts
Risks and uncertainties associated with weather conditions and wildlife restrictions can shorten the winter
drilling season and impact the spring and summer drilling programs, potentially resulting in increased
costs or reduced production.
Environmental Compliance
For a discussion of environmental risks at our NG operations, refer to the "Legal and Regulatory Risks"
outlined in the "Risk Factors" section of this Annual Information Form, as well as the "Asset Retirement
Obligations" section under "Critical Accounting Estimates" in the "Suncor Overview and Strategic
Priorities" section of our MD&A.
REFINING AND MARKETING (R&M)
Consistent with the company’s organizational restructuring during the first quarter of 2007, results from
our Canadian and U.S. downstream marketing and refining operations have been combined into a single
business segment – Refining and Marketing.
Our Canadian-based refining and marketing business operates in Central Canada. Our refinery in
Sarnia, Ontario, has a crude oil capacity of 70,000 bpd and refines petroleum feedstock from Oil Sands
and other sources into gasoline, distillates, and petrochemicals with the majority of these refined products
being distributed in Ontario. Our ethanol facility in St. Clair, Ontario, produces ethanol from corn, which is
used for blending into our fuels and is also sold to third parties.
As a marketing channel for our Canadian refined products, our Ontario retail networks generated
approximately 51% of R&M’s Canadian 2007 sales volume of 112,000 bpd. The retail networks are
comprised of Sunoco-branded retail service stations, Sunoco-branded Fleet Fuel Cardlock sites, and two
50% retail joint venture6 businesses that operate Pioneer-branded retail service stations, UPI-branded
retail service stations and UPI bulk distribution facilities for rural and farm fuels. Approximately 44% of
R&M’s Canadian refined product sales in 2007 were wholesale and industrial sales. Sun Petrochemicals
Company, a 50% joint venture between a Suncor subsidiary and a Toledo, Ohio-based refinery,
generated the remaining 5% of sales.
Our U.S.-based refining and marketing business includes a refining facility, a retail network, and a
pipeline transportation business primarily in Colorado and Wyoming. The Commerce City, Colorado
refining facility has a current combined crude distillation capacity of 90,000 bpd. The majority of the
refined products from the Commerce City refinery are distributed in Colorado.
Approximately 18% of R&M's US petroleum products sales in 2007 (2006 – 18%) were sold through a
distribution network in Colorado that sells gasoline and diesel fuel to retail customers. In 2007,
approximately 74% (2006 – 74%) of our U.S.-based petroleum product sales volumes were to industrial,
commercial, wholesale and refining customers in Colorado, representing primarily jet fuels, diesel and
gasoline. Asphalt sales comprised the remaining 8% of R&M’s U.S. refined product sales volumes for
2007 (2006 – 8%).
In addition to our downstream refining and marketing operations, this business also includes an energy
marketing and trading business. Energy marketing and trading activities consist of both third party crude
oil marketing, and financial and physical derivatives trading activities.
6
Pioneer Group Inc. is an independent company with which Suncor has a 50% joint venture partnership. UPI Inc. is a 50% joint
venture company Suncor has with GROWMARK Inc., a Midwest U.S. retail farm supply and grain marketing cooperative.
12
Procurement of Feedstocks
The Sarnia refinery uses both synthetic and conventional crude oil. In 2007, the Sarnia refinery procured
approximately 50% (2006 – 55%) of its synthetic crude oil feedstock from our Oil Sands production. In
2007, 43% (2006 – 60%) of the crude oil refined at the Sarnia Refinery was synthetic crude oil. The
balance of the refinery’s synthetic crude oil, as well as its conventional and condensate feedstocks, were
purchased from others under month to month contracts. In the event of a significant disruption in the
supply of synthetic crude oil, the refinery has the flexibility to substitute other sources of sweet or sour
conventional crude oil.
We procure conventional crude oil feedstock for our Sarnia refinery primarily from Western Canada,
supplemented from time to time with crude oil from the United States and other countries. Foreign crude
oil is delivered to Sarnia via pipeline from the United States Gulf Coast or via the Enbridge Pipeline from
Montreal. We have not made any firm capacity commitments on these pipeline systems. Crude oil is
procured from the market on a spot basis or under contracts which can be terminated on short notice.
In 1998, EM&R signed a 10-year feedstock agreement with a Sarnia-based petrochemical refinery, Nova
Chemicals (Canada) Ltd. Under this buy/sell agreement, we obtain feedstock that is more suitable for
production of transportation fuels in exchange for feedstock more suitable for petrochemical cracking.
We also enter into reciprocal buy/sell or exchange arrangements with other refining companies from time
to time as a means of minimizing transportation costs, balancing product availability and enhancing
refinery utilization. We also purchase refined products in order to meet customer requirements.
In July 2006, with the completion of our ethanol facility, we began producing ethanol for use in our
blended gasoline products, and for sales to third parties.
The Commerce City refining operation uses both conventional and synthetic crude oil. Approximately
one-quarter of the refinery’s crude oil is purchased from Canadian sources, with the remainder supplied
from sources in the United States, primarily from the Rocky Mountain region.
The refinery’s crude oil purchase contracts have terms ranging from month-to-month to multi-year. In the
event of a significant disruption in the supply of crude oil, the refinery has the flexibility to substitute other
sources of sweet or sour crude oil on a spot purchase basis.
With the completion of our diesel desulphurization and oil sands integration projects, we are now capable
of processing of up to 40,000 bpd and 15,000 bpd of Oil Sands sour crude oil at our Canadian and U.S.
refineries, respectively.
Refining Operations
Canadian
The Sarnia refinery produces transportation fuels (gasoline, diesel, propane and jet fuel), heating fuels,
liquefied petroleum gases, residual fuel oil, asphalt feedstock, benzene, toluene, mixed xylenes and
orthoxylene, as well as the petrochemicals A-100 and A-150 that are used in the manufacture of paint
and chemicals.
In 2007 the refinery had capacity to refine 70,000 bpd of crude oil. Refining units include a 23,300 bpd
hydrocracker and a 5,400 bpd alkylation unit. The petrochemical facilities have a capacity of 13,100 bpd,
the aromatic solvents unit has a capacity of approximately 1,000 bpd, and our gasoline desulphurization
unit has the capacity to process 10,250 bpd. The distillate hydrotreater that became operational in July
2006 has a processing capacity of 43,600 bpd.
In 2007 the refinery had cracking capacity of 40,200 bpd from a Houdry catalytic cracker ("catcracker")
and a hydrocracker. Approximately 40% of the cracking capacity was attributable to the catcracker,
which uses older technology. In 2004, a study to assess the catcracker concluded that, with planned
improvements and upgrades, it can continue to be operated economically and safely for at least 10 years.
13
A range of replacement options for the catcracker was identified during a review in 2005. Analysis of
these and other options will continue.
Overall, crude utilization averaged 98% for 2007, compared to 78% in 2006. In 2007 the utilization rate
was impacted by a shutdown to tie-in new facilities while in 2006 the utilization rate was impacted by a
major maintenance shutdown.
The refinery’s external steam and electricity needs are currently being met primarily by supply from the
Sarnia Regional Co-generation Project.
United States
Refining units include two fluidized catalytic crackers with a 29,500 bpd combined capacity, a 19,000 bpd
distillate hydrotreater and a 26,000 bpd gas oil hydrotreater. The refined gasoline products from the
Commerce City refinery primarily supply R&M’s marketing operations in Colorado. Refining sales in 2007
averaged approximately 99,600 bpd (15,800 m3 per day) compared to 90,600 bpd (14,400 m3 per day) in
2006.
The Commerce City refining operation is a high conversion operation that produces a full range of
products, including gasoline, jet fuels, diesel and asphalt. The refinery produces a crude slate containing
approximately one-third heavy, high sulphur crude. Overall, crude utilization averaged 99% in 2007
(2006 – 92%).
The following chart sets out R&M’s total daily crude input and average refinery utilization rates for both its
combined Canadian and U.S. refinery operations in 2007 and 2006.
Total Canadian and U.S. Refinery Capacity
Average daily crude input (barrels per day)
Average crude utilization rate (%)(1)
2007
157,600
98
2006
136,700
85
Notes:
(1)
Based on crude unit capacity and input to crude units.
In the normal course of our operations we regularly complete planned maintenance shutdowns of our
refinery facilities. These shutdowns are scheduled, and provide both preventative maintenance and
capital replacement which is expected to maintain our operational efficiency. During 2007, significant
maintenance shutdowns were successfully completed at both our Sarnia and Commerce City area
refining facilities.
14
Principal Products
Set forth below is information on daily sales volumes and the corresponding percentage of R&M’s
consolidated operating revenues by product for the last two years.
Product:
2007
(thousands
of cubic
meters per
day)
Transportation Fuels
Gasoline
Retail
Joint Ventures
Other
Jet Fuel
Diesel
Sub-total – Transportation Fuels
Petrochemicals
Asphalt
Other
Total Refined Products
Other Non-Refined Products(1)
Energy Marketing & Trading
Total %
5.2
3.1
8.5
2.3
8.3
27.4
0.9
1.7
3.5
33.5
2006
(% of R &M's
consolidated
revenues)
13
5
24
4
18
64
2
2
5
73
2
25
100
(thousands
of cubic
meters per
day)
5.3
3.0
7.6
1.7
6.8
24.4
0.9
1.2
3.0
29.5
(% of R&M's
consolidated
revenues)
19
6
23
4
18
70
3
1
5
79
2
19
100
Note:
(1)
Includes ancillary revenues
Principal Markets
Canadian
Approximately 51% (2006 – 58%) of R&M’s Canadian sales volumes are marketed through retail
networks, including the Sunoco-branded retail network, joint venture owned retail stations and cardlock
operations. In 2007, this network was comprised of:
o
272 (2006 – 272) Sunoco-branded retail service stations
o
151 (2006 – 151) Pioneer-operated retail service stations
o
55 (2006 – 53) UPI-operated retail service stations and a network of 13 bulk distribution
facilities for rural and farm fuels
o
48 (2006 – 36) Sunoco branded Fleet Fuel Cardlock sites
UPI Inc. is a joint venture company owned 50% with GROWMARK Inc., a U.S. Midwest agricultural
supply and grain marketing cooperative. Pioneer is a 50% joint venture partnership with The Pioneer
Group Inc.
Refined petroleum products (excluding petrochemicals) are marketed under several brands, including the
Company’s Canadian "Sunoco" trademark. R&M’s other principal trademarks include “Ecowash”, our
award-winning car wash and "Gold Diesel", our premium low-sulphur diesel product.
15
Approximately 44% (2006 – 36%) of R&M’s Canadian sales volumes are sold to industrial, commercial,
wholesale and refining customers, primarily in Ontario. R&M also supplies industrial and commercial
customers in Quebec through long-term arrangements with other regional refiners.
R&M Canadian operations market toluene, mixed xylenes, orthoxylene and other petrochemicals,
primarily in Canada and the U.S., through Sun Petrochemicals Company. R&M has a 50% interest in
Sun Petrochemicals Company, a petrochemical marketing joint venture that markets products from our
Sarnia, Ontario refinery and from a Toledo, Ohio, refinery owned by the joint venture partner. Sun
Petrochemicals Company markets petrochemicals used to manufacture plastics, rubber, synthetic fibres,
industrial solvents and agricultural products, and gasoline octane enhancers. All benzene production is
sold directly to other petrochemical manufacturers in Sarnia, Ontario.
R&M’s share of total refined product sales in its primary Canadian market of Ontario was approximately
20% in 2007 (2006 – 18%). Transportation fuels accounted for 78% of R&M’s Canadian sales volumes in
2007 (2006 – 82%); and petrochemicals accounted for 5% (2006 – 6%). The remaining volumes included
other refined products such as heating fuels, heavy oils and liquefied petroleum gases, and were sold to
industrial users and resellers.
Refined petroleum products are also supplied to the Pioneer and UPI joint ventures. We have a separate
supply agreement with each of UPI and Pioneer. These supply agreements are evergreen and are
subject to termination only in accordance with the terms of the various agreements between the parties.
United States
Approximately 18% of R&M's U.S. sales volumes are marketed through Phillips 66 ® - branded retail
outlets. This network is comprised of:
•
44 owned Phillips 66 ® - branded retail sites, which account for approximately 5% of R&M’s U.S.
sales volumes; and
•
Supply agreements with 173 Phillips 66 ® branded marketer outlets throughout the state of Colorado,
which account for approximately 13% of R&M’s U.S. sales volumes. These agreements are typically
for three year terms with provision for automatic three year renewal periods on an evergreen basis.
We have an exclusive license from ConocoPhillips to use the Phillips 66 ® and related trademarks and
brand names in Colorado until December 31, 2012.
The Denver refining operation also supplies all of its asphalt production to SemMaterials, L.P. Asphalt
sales made up about 8% of R&M’s U.S. 2007 sales volumes (2006 – 8%).
Approximately 74% of R&M's U.S. sales volumes are sold to industrial, commercial, wholesale and
refining customers, primarily in Colorado, of which approximately 10% was sold under a long-term supply
agreement with ConocoPhillips (expiring in 2013) and 23% was sold under a supply agreement with
Valero (expiring in 2008).
R&M estimates its U.S. sales of total light fuels refined product in 2007 represented a market share, in its
primary market of Colorado, of approximately 40% (2006 – 40%). Within this market, R&M’s Phillips 66 ®
- branded sites represent a 13% market share (2006 – 15%).
Transportation and Distribution
R&M operations use a variety of transportation modes to deliver products to market, including pipeline,
water, rail and road.
For our Canadian operations, R&M owns and operates petroleum transportation, terminal and dock
facilities, including storage facilities and bulk distribution plants in Ontario. The major mode of transporting
gasoline, diesel, jet fuel and heating fuels from the Sarnia refinery to core markets in Ontario is the Sun-
16
Canadian Pipe Line, which is 55% owned by Suncor and 45% owned by another refiner. The pipeline
operates as a private facility for its owners, serving terminal facilities in Toronto, Hamilton and London.
We also have pipeline access, subject to availability, to petroleum markets in the Great Lakes region of
the United States by way of a pipeline system in Sarnia operated by a U.S. based refiner. This link to the
U.S. allows R&M’s Canadian operations to move products to market or obtain feedstocks/products when
market conditions are favourable in the Michigan and Ohio markets.
For our U.S. operations, approximately sixty percent of crude oil processed at the Denver refining
operation is transported via pipeline, with the remainder supplied via truck. R&M owns and operates the
Rocky Mountain Crude system, which runs from Guernsey, Wyoming to Denver, Colorado. This pipeline
is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers.
We also operate a crude pipeline, the Centennial pipeline, from Guernsey, Wyoming to Cheyenne,
Wyoming. Until September 27, 2007, we owned approximately 65% of the Centennial pipeline. Effective
September 27, 2007, we purchased the remaining 35% interest from another area refiner, and are now
the 100% owner of the Centennial pipeline.
The Rocky Mountain crude system had a capacity of 38,000 bpd in 2007 for the Guernsey to Cheyenne
leg of the pipeline and 73,500 bpd for the Cheyenne to Denver leg of the pipeline. In 2007, the Rocky
Mountain Crude system utilized approximately 85% (2006 – 81%) of its capacity with average throughput
of 27,600 bpd (2006 – 28,200 bpd) in the Guernsey to Cheyenne leg of the pipeline, and 67,700 bpd
(2006 - 62,400 bpd) in the higher capacity Cheyenne to Denver leg. During the same period, the
Centennial pipeline utilized approximately 80% (2006 – 85%) of capacity, with an average throughput of
approximately 50,800 bpd (2006 – 54,400 bpd).
R&M’s U.S. operations have both truck and rail loading racks at the Denver area refining facility with
product loading capacity in excess of 30,000 bpd, a one mile long 7,000 bpd jet fuel pipeline that
connects to a common carrier pipeline system for deliveries to the Denver International Airport, and a four
mile long 14,000 bpd diesel pipeline that delivers diesel product directly to the Union Pacific railroad yard
in Denver, Colorado.
In both our Canadian and U.S. operations, we believe our own storage facilities, and those under longterm contractual arrangements with other parties, are sufficient to meet our current and foreseeable
storage needs.
Competitive Conditions
Competitive conditions affecting our R&M business are described under "Competition" in the "Risk
Factors" section of this Annual Information Form.
Environmental Compliance
Due to increasingly stringent regulations regarding water discharges, we are required to improve water
treatment capability at our Commerce City refining operation, which will require additional water treating
equipment for the discharge of process waste water. It is estimated this will cost approximately $44 million
to $49 million (US$45 to $50 million) and is expected to be completed in the 2008 to 2010 timeframe.
During 2007 we spent approximately $12 million (US $11 million) on the ammonia phase waste water
project.
The Ontario provincial, Colorado state and Canadian federal governments are in various stages of
developing greenhouse gas management legislation and regulation. At this time, no such legislation has
been tabled in any of these jurisdictions and any potential impacts are unknown.
For a discussion of environmental risks at our R&M operations, refer to the "Legal and Regulatory Risks"
outlined in the "Risk Factors" section of this Annual Information Form, as well as the "Asset Retirement
Obligations" section under "Critical Accounting Estimates" in the "Suncor Overview and Strategic
Priorities" section of our MD&A.
17
MATERIAL CONTRACTS
During the year ended December 31, 2007, we have not entered into any contracts, nor are there any
contracts still in effect, that are material to our business, other than contracts entered into in the ordinary
course of business and the Shareholder Rights Plan dated April 28, 2005.
RESERVES ESTIMATES
As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory
authorities, including the reporting of our reserves in accordance with National Instrument 51-101
Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). However, we have received an
exemption from Canadian securities regulatory authorities permitting us to report our reserves in
accordance with U.S. disclosure requirements. Pursuant to U.S. disclosure requirements, we disclose net
proved conventional oil and gas reserves, including natural gas reserves and bitumen reserves from our
Firebag in-situ leases, using constant dollar cost and pricing assumptions. As there is no recognized
posted bitumen price, these assumptions are based on a posted benchmark oil price, adjusted for
transportation, gravity and other factors that create the difference ("differential") in price between the
posted benchmark price and Suncor’s bitumen. Both the posted benchmark price and the differential are
generally determined as of a point in time, namely December 31 ("Constant Cost and Pricing"). Reserves
from our Firebag in-situ leases are reported as barrels of bitumen, using these Constant Cost and Pricing
assumptions (see "Required U.S. Oil and Gas Disclosure – Proved Conventional Oil and Gas Reserves"
for net proved conventional oil and gas reserves).
Pursuant to U.S. disclosure requirements, we also disclose gross and net proved and probable mining
reserves. The estimates of our gross and net mining reserves are based in part on the current mine plan
and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of
synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 78.5% for proven
reserves, and 80% for proved plus probable reserves. The lower yield rate applied to proven reserves
reflects historical operational levels. The 80% proved plus probable reserves yield rate reflects
anticipated yield levels once operational performance issues have been addressed.
During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option
to transition to the generic bitumen-based royalty regime commencing in 2009, allowing us to prepare an
estimate of our net mining reserves. The estimate of our net mining reserves reflects the value of Alberta
Crown, overriding, and freehold royalty burdens under constant December 31 pricing and our exercise of
the option electing to transfer to a bitumen based Crown royalty effective at the beginning of 2009 (See "
Required U.S. Oil and Gas and Mining Disclosure – Proved and Probable Oil Sands Mining Reserves" for
both gross and net, proved and probable mining reserves). Our Firebag in-situ leases are subject to
Crown royalty based on bitumen, rather than synthetic crude oil. As there is currently no legislated
methodology for determining bitumen value for Alberta Crown royalty purposes, bitumen value for
determining royalties has been assumed to correspond to Firebag bitumen sales to our upgrader.
However, determination of bitumen value for royalty purposes is currently under review by the
Government of Alberta. In October 2007, the Government of Alberta proposed changes to the royalty
regime. In January 2008, Suncor entered into a Royalty Amending Agreement to transition to the new
royalty framework assuming the government enacts their proposed changes. Neither the governments
proposed changes, nor our Royalty Amending Agreement have been reflected in the following reserve
estimates. For a full discussion of our Crown royalties, see "Oil Sands Crown Royalties" and “Natural
Gas Crown Royalties” in the "Suncor Overview and Strategic Priorities" section of our MD&A.
In addition to reporting our reserves in accordance with U.S. disclosure requirements, the exemption
issued by Canadian securities regulatory authorities permits us to provide voluntary additional disclosure.
We provide this voluntary additional disclosure to show aggregate proved and probable oil sands
reserves, including both mining and Firebag reserves. In our voluntary disclosure we report our
aggregate reserves on the following basis:
18
•
Gross and net proved and probable mining reserves are consistent with required US mining
disclosures, however the voluntary disclosure reflects normalized constant dollar cost and pricing
assumptions. These assumptions use a posted benchmark oil price as at December 31, but
apply a differential generally intended to represent a normalized annual average for the year
("Annual Average Differential Pricing"), rather than a point in time differential, in accordance with
CSA Staff Notice 51-315 (reported as barrels of synthetic crude oil based upon a net coker, or
synthetic crude oil, yield from bitumen of 78.5% for proved reserves and 80% for proved plus
probable reserves); and
•
Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated
based on Annual Average Differential Pricing. Bitumen reserves estimated on this basis are
subsequently converted, for aggregation purposes only, to barrels of synthetic crude oil based on
a net coker or synthetic crude oil yield from bitumen of 80% for proved and proved plus probable
reserves.
Accordingly, our voluntary disclosures of reserves from our Firebag in-situ leases will differ from our
required U.S. disclosure in four ways. Reserves from our Firebag in-situ leases under our voluntary
disclosure:
(a)
are disclosed on a gross basis as well as the required net basis under U.S. disclosure
requirements;
(b)
are converted from barrels of bitumen under U.S. disclosure requirements to barrels of synthetic
crude oil for aggregation purposes;
(c)
include proved plus probable reserves, rather than proved reserves only under U.S. disclosure
requirements; and
(d)
are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance
with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S.
disclosure requirements.
Comparisons of reserve estimates under “Required U.S. Oil and Gas Mining Disclosure” and “Voluntary
Oil Sands Reserve Disclosure” may show material differences based on the pricing assumptions used,
whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, whether
probable reserves are included, and whether the reserves are reported on a gross or net basis. These
differences were significant for 2005 and 2007 reporting given the considerably lower constant price
assumptions. At December 31, 2006, there was no difference arising from pricing. Refer to "Voluntary Oil
Sands Reserves and Resources Disclosure - Estimated Gross and Net Proved and Probable Oil Sands
Reserves Reconciliations".
In addition to our required and voluntary reserves disclosures, we have also elected to disclose our best
estimate remaining recoverable resources for both mining and in-situ at December 31, 2007. These
disclosures follow the requirements in NI 51-101.
All of our reserves and resources have been evaluated as at December 31, 2007 by independent
petroleum consultants, GLJ Petroleum Consultants Ltd. ("GLJ"). In reports dated February 19, 2008 for
Oil Sands Mining and February 11, 2008 for Oil Sands In-Situ (collectively referred to herein as "GLJ Oil
Sands Reports"), GLJ evaluated our resources and our proved and probable reserves on our oil sands
mining and Firebag in-situ leases pursuant to U.S. disclosure requirements using Constant Cost and
Pricing assumptions.
Estimates in the GLJ Oil Sands Reports consider recovery from leases for which regulatory applications
have been submitted and no impediment to the receipt of regulatory approval is expected. The mining
reserve estimates are based on a detailed geological assessment and also consider industry practice,
19
drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life,
project implementation commitments, and regulatory constraints.
For Firebag in-situ reserve estimates, GLJ considered similar factors such as our regulatory approval or
likely impediments to the receipt of pending regulatory approval, project implementation commitments,
detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous
commercial projects and drill density. Our proved reserves are delineated to within 80 acre spacing with
3D seismic control (or 40 acre spacing without 3D seismic control) while our probable reserves are
delineated to within 160 acre spacing without 3D seismic control. The major facility expenditures to
develop our proved undeveloped reserves have been approved by our Board. Plans to develop our
probable undeveloped reserves in subsequent phases are under way but have not yet received final
approval from our Board.
In a report dated February 11, 2008 ("GLJ NG Report"), GLJ also evaluated our proved reserves of
natural gas, natural gas liquids and crude oil (other than reserves from our mining leases and the Firebag
in-situ reserves) as at December 31, 2007.
Our reserves estimates will continue to be impacted by both drilling data and operating experience, as
well as technological developments and economic considerations.
Net reserves represent Suncor’s undivided percentage interest in total reserves after deducting Crown
royalties, freehold and overriding royalty interests. Reserve estimates are based on assumptions about
future prices, production levels, operating costs, capital expenditures, and the current Government of
Alberta royalty regime. These assumptions reflect market and regulatory conditions, as required, at
December 31, 2007, which could differ significantly from other points in time throughout the year, or future
periods. Changes in market and regulatory conditions and assumptions can materially impact the
estimation of net reserves.
REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE
Proved and Probable Oil Sands Mining Reserves
Millions of barrels of synthetic
(1)
crude oil
December 31, 2006
Revisions of previous estimates
Extensions and discoveries
Production
December 31, 2007
Proved
Gross(2)
Net(3)
1,709
(1)
(74)
1,634
1,507
103
(66)
1,544
Probable
Gross(2)
Net(3)
634
106
740
564
149
713
Proved & Probable
Gross(2)
Net(3)
2,343
105
(74)
2,374
2,071
252
(66)
2,257
Notes:
(1)
Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 78.5% for proved
reserves, and 80% for proved plus probable reserves. The lower yield rate applied to proved reserves reflects historical
operational levels that have fallen below management expectations. The 80% proved plus probable reserves yield rate
reflects a return to management’s target levels once operational performance issues have been addressed.
(2)
Our gross mining reserves are based in part on our current mine plan and estimates of extraction recovery and upgrading
yields, rather than an analysis based on constant dollar or forecast pricing and cost assumptions.
(3)
Net mining reserves reflect the value of Crown, freehold and overriding royalty burdens under constant December 31
pricing and incorporates our exercised option to elect to transfer to a bitumen based Crown royalty effective at the
beginning of 2009. Neither the current proposed Alberta royalty regime changes, nor our Royalty Amending Agreement
have been incorporated. If enacted, at current oil prices we expect our future royalty payments to increase and our net
reserves to decrease. Refer to the “Alberta Crown Royalties” risk, as outlined in the “Risk Factors” section of this AIF.
20
Significant Mining Leases
Interest Held
Leases:
Permits:
Fee Lots:
Total
Description
7279080T19
7597030T11
7280100T25
7387060T04
7279120092
7280060T23
7498050014
7405080347
7405030690
7405010854
7405010853
7400120007
7405080346
7401100029
7006060389
7006060390
7006060391
1
2
3
4
5
6
Gross Acres
18,541
2,454
49,365
4,469
1,600
36,526
240
5,693
633
22,773
22,773
22,773
5,060
10,120
8,853
1,897
3,162
1,894
1,972
1,967
1,886
1,881
1,483
228,015
Expiry Date (4)
Retention
Conditions
n/a
n/a
n/a
n/a
n/a
n/a
May 27, 2019
Aug. 24, 2020
Mar. 23, 2020
Jan. 26, 2020
Jan. 26, 2020
Dec. 13, 2015
Aug. 24, 2020
Oct. 17, 2016
May 31, 2011
May 31, 2011
May 31, 2011
n/a
n/a
n/a
n/a
n/a
n/a
(1)
(1)
(1)
(1)
(1)
(1)
(2)
(2)
(2)
(2)
(2)
(2)
(2)
(2)
(3)
(3)
(3)
n/a
n/a
n/a
n/a
n/a
n/a
1) These producing leases can be retained indefinitely so long as agreed minimum levels of production
are maintained.
2) Annual lease rentals are required to maintain these leases until the indicated expiry dates for the
primary terms of the leases. Upon application for continuation prior to the indicated expiry dates,
leases can be retained beyond the indicated expiry dates if they meet the minimum level of evaluation
and if:
a) the leases are in production and sustain agreed minimum levels of production; or
b) escalating rents are paid. Escalating rents start at $7/hectare/year and double every three years
to a maximum of $224/hectare/year.
3) Annual rentals are required to maintain these permits until the indicated expiry dates for the terms of
the permits. Upon application prior to the indicated expiry dates, a permit can be converted to a 15
year term lease if the minimum level of evaluation criteria has been met. Upon conversion of a permit
to a lease, continuation of the resulting lease is as set out in (2) above.
4) There is no undeveloped acreage subject to expiration in each of the next three years.
21
Oil Sands Mining Operating Statistics
The following table sets out certain operating statistics for our Oil Sands mining operations.
Measurements are averages based on measurement statistics throughout the year and accordingly,
should be read as approximations. Statistics for the Oil Sands Firebag in-situ operations are addressed
under the heading "Proved Conventional Oil and Gas Reserves" and "Sales, Production, Well Data, Land
Holdings and Drilling Activity - Conventional".
2007
Total mined volume (1)
millions of tonnes ...........................................................
(1)
Mined volume to tar sands ratio ..................................
Tar sands mined
millions of tonnes ...........................................................
Average bitumen grade (weight %) ................................
Crude bitumen in mined tar sands
millions of tonnes ...........................................................
Average extraction recovery % ......................................
Crude bitumen production
(2)
millions of cubic meters ...............................................
Gross synthetic crude oil produced
Thousands of barrels per day(3)......................................
2006
2005
331.3
40.6%
356.2
41.8%
313.7
32.0%
134.4
12.4%
149.0
12.8%
100.5
12.2%
16.6
92.8%
19.1
93.1%
12.3
92.6%
15.4
17.6
11.4
235.0
231.9
152.2
Notes:
(1)
Includes pre-stripping of mine areas and reclamation volumes.
(2)
Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and
the appropriate conversion factor.
(3)
Cubic meters are converted to barrels at the conversion factor of 6.29. Bitumen production from Firebag is upgraded and
included in the base operations production. Therefore the mining production reported above will no longer agree to the
operating statistics.
22
Proved Conventional Oil and Gas Reserves
The following table is provided on a net basis in accordance with the provisions of the Financial
Accounting Standards Board’s Statement No. 69 (Statement 69). This statement requires disclosure
about conventional oil and gas activities only, and therefore our Oil Sands mining reserves are excluded,
while in-situ Firebag reserves are included.
NET PROVED RESERVES(1)
Crude Oil, Natural Gas Liquids and Natural Gas
Constant Cost and Pricing as at December 31
December 31, 2004
Revisions of previous estimates
Purchases of minerals in place
Extensions and discoveries
Production
Sales of minerals in place
December 31, 2005
Revisions of previous estimates
Improved Recovery
Purchases of minerals in place
Extensions and discoveries
Production
Sales of minerals in place
December 31, 2006
Revisions of previous estimates
Improved Recovery
Purchases of minerals in place
Extensions and discoveries
Production
Sales of minerals in place
December 31, 2007
Oil Sands
business:
Firebag – Crude
Oil
(millions of
barrels of
(2),(3),(4)
bitumen)
639
(7)
632
(57)
340
(12)
903
68
99
(13)
1,057
(3)
(6)
(6)
Natural Gas
business:
Crude Oil and
Natural Gas
Liquids
(millions of
barrels)
Total
(millions of
barrels)
8
(1)
7
1
(1)
7
(1)
6
8
639
(8)
639
(57)
340
1
(13)
910
68
99
(14)
1,063
7
7
6
6
7
144
194
192
Natural Gas
business:
Natural Gas
(billions of
cubic feet)
446
14
40
(50)
(1)
449
5
26
(53)
(1)
426
4
19
33
(53)
(1)
428
(5)
(5)
(5)
Proved Developed
December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007
137
188
186
385
387
365
379
Notes:
(1)
Our undivided percentage interest in reserves, after deducting Crown royalties, freehold royalties and overriding royalty
interests. Our Firebag leases are only subject to Crown royalties.
(2)
Although we are subject to Canadian disclosure rules in connection with the reporting of our reserves, we have received
exemptive relief from Canadian securities administrators permitting us to report our proved reserves in accordance with U.S.
disclosure practices. See Reliance on Exemptive Relief on pg 50.
(3)
Estimates of proved reserves from our Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at
December 31. In 2004, due to unusually low year-end posted benchmark oil prices, and unusually high year-end diluent
prices, our proved reserves were determined to be uneconomic. Since 2005 we have rebooked our proved reserves, and
these continued to be economically viable through 2007.
(4)
We have the option of selling the bitumen production from these leases or upgrading the bitumen to synthetic crude oil.
23
(5)
Natural gas infill drilling included in total revisions for 2007 was 16 billion cubic feet (bcf), (2006 – 11 bcf; 2005 – 23 bcf).
(6)
Improved recovery recognizes a portion of our Firebag Stage 3 expansion project.
All reserves are located in Canada. There has been no major discovery or other favourable or adverse event
that caused a significant change in estimated proved reserves since December 31, 2007. We do not have
long-term supply agreements or contracts with governments in which we act as producer nor do we have
any interest in oil and gas operations accounted for by the equity method.
Capitalized Costs Relating to Oil and Gas Activities (1)
As at December 31,
($ millions)
2007
Proved properties ........................................................
Unproved properties ....................................................
Other support facilities and equipment.........................
Total cost .....................................................................
Accumulated depreciation and depletion .....................
Net capitalized costs ....................................................
2006
4,896
298
24
5,218
(1,306)
3,912
3,869
224
22
4,115
(1,041)
3,074
Note:
(1)
Capitalized costs do not include costs related to the associated upgrading expansion projects.
Costs Incurred in Oil and Gas Acquisition, Exploration and Developmental Activities (1)
For the years ended December 31,
($ millions)
Property acquisition costs
Proved properties.........................................................
Unproved properties.....................................................
Exploration costs............................................................
Development costs.........................................................
Asset retirement obligations ...........................................
Total capital and exploration expenditures .....................
2007
140
32
142
1,459
30
1,803
2006
29
247
688
35
999
2005
1
9
148
552
4
714
Note:
(1)
Costs incurred do not include costs related to associated upgrading expansion projects.
24
Results of Operations for Oil and Gas Production
For the years ended December 31,
($ millions)
Revenues
Sales to unaffiliated customers ......................................
Transfers to other operations .........................................
Expenses
Production costs.............................................................
Depreciation, depletion and amortization .......................
Exploration .....................................................................
Gain on disposal of assets .............................................
Other related costs.........................................................
Operating profit before income taxes .............................
Related income taxes.....................................................
Results of operations .....................................................
2007
2006
2005
492
431
923
516
387
903
670
52
722
362
264
93
47
766
157
(10)
147
291
215
87
(4)
40
629
274
(38)
236
213
145
66
(12)
39
451
271
(98)
173
Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved
Oil and Gas Reserves after Income Taxes
In computing the standardized measure of discounted future net cash flows from estimated production of
proved oil and gas reserves after income taxes, assumptions other than those mandated by Statement 69
could produce substantially different results. We caution against viewing this information as a forecast of
future economic conditions or revenues, and do not consider it to represent the fair market value of our
Firebag in-situ and Natural Gas properties. Figures are based on our actual year-end commodity prices.
Readers are cautioned that commodity prices are volatile. To illustrate this volatility, the following table
sets out certain commodity benchmark prices over the past three years:
Year end natural gas price (AECO- $/GJ)
Year end crude oil price (WTI US$/bbl)
Year end light/heavy crude oil differential, WTI at Cushing less LLB
at Hardisty (US$/bbl)
2007
6.26
95.98
41.72
2006
7.52
62.09
17.99
2005
10.22
59.45
26.35
Actual future net cash flows may differ from those estimated due to, but not limited to, the following:
•
Production rates could differ from those estimated both in terms of timing and amount;
•
Future prices and economic conditions will likely differ from those at year-end;
•
Future production and development costs will be determined by future events and may differ from
those at year-end;
•
Estimated income taxes and royalties may differ in terms of amounts and timing due to the above
factors as well as changes in enacted rates, bitumen valuation methodology, and the impact of future
expenditures on unproved properties;
The standardized measure of discounted future net cash flows is determined by using estimated
quantities of proved reserves and taking into account the future periods in which they are expected to be
developed and produced based on year-end economic conditions. The estimated future production is
priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and
determinable price escalations provided by contract. The resulting estimated future cash inflows are
reduced by estimated future costs to develop and produce the proved reserves based on year-end cost
levels. In addition, we have also deducted certain other estimated costs deemed necessary to derive the
estimated pretax future net cash flows from the proved reserves including direct general and
25
administrative costs of exploration and production operations and estimated cash flows related to asset
retirement obligations. Deducting future income tax expenses then further reduces the estimated pre-tax
future net cash flows. Such income taxes are determined by applying the appropriate year-end statutory
tax rates, with consideration of future tax rates already legislated, to the future pre-tax cash flows relating
to our proved oil and gas reserves less the tax basis of the properties involved. Royalties are determined
based upon the appropriate royalty rates and regimes in effect at year end for Firebag and Natural Gas
production and, in the case of Firebag, reflects that Firebag is classified as a separate operation for
royalty purposes, as described in our MD&A (see "Oil Sands Crown Royalties and Cash Income Taxes" in
the "Suncor Overview and Strategic Priorities" Section of our MD&A). The resultant future net cash flows
are reduced to present value amounts by applying the Statement 69 mandated 10% discount factor. The
result is referred to as "Standardized Measure of Discounted Future Net Cash Flows from Estimated
Production of Proved Oil and Gas Reserves after Income Taxes".
($ millions)
Future cash flows ...........................................................
Future production costs..................................................
Future development costs..............................................
Other related future costs...............................................
Future income tax expenses ..........................................
Subtotal
*Discount at 10%............................................................
Standardized measure of discounted future net cash
flows from estimated production of proved oil and gas
reserves after income taxes ...........................................
2007
2006
2005
31,227
(15,963)
(8,002)
(742)
(2,203)
4,317
(3,807)
32,882
(12,264)
(5,648)
(612)
(4,221)
10,137
(6,768)
16,444
(10,181)
(1,705)
(464)
(1,216)
2,878
(1,214)
510
3,369
1,664
Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows from
Estimated Production of Proved Oil and Gas Reserves after Income Taxes
($ millions)
2007
2006
Balance, beginning of year ..........................................................................
Sales and transfers of oil and gas produced, net of production costs .........
Net changes in prices and production costs ................................................
Changes in estimated future development costs
Extensions, discoveries and improved recovery, less related costs
Development costs incurred during the period ............................................
Revisions of previous quantity estimates.....................................................
Purchases of reserves in place ...................................................................
Sale of reserves in place
Accretion of discount ...................................................................................
Net changes in income taxes ......................................................................
Other related costs ......................................................................................
Balance, end of year....................................................................................
3,369
(483)
(3,226)
(2,151)
72
1,459
(4)
37
(2)
472
934
33
510
1,664
(559)
1,907
(1,141)
59
772
1,051
(2)
231
(714)
101
3,369
2005
1,074
(456)
737
(573)
162
557
440
(4)
125
(470)
72
1,664
Sales, Production, Well Data, Land Holdings and Drilling Activity - Conventional
The following tables set out additional information on our conventional oil and gas producing activities,
including our Firebag in-situ operation. Information with respect to our Oil Sands mining operations is not
covered by the information below but is addressed in the preceding information under "Oil Sands Mining
Operating Statistics".
26
Sales Prices(1), (2)
For the year ended December 31,
Crude Oil and Bitumen ($/bbl)……………….……………………………………….
NGL ($/bbl)……………………………………………………………………………..
Natural Gas ($/mcf)……………………………………………………………………
2007
37.67
53.32
6.32
2006
38.94
44.96
7.15
2005
45.86
50.70
8.57
Notes:
(1)
Production is based in Western Canada.
(2)
Prices are calculated using our undivided percentage interest production before royalties.
Production Costs
For the year ended December 31,
2007
2006
2005
13.63
11.92
10.86
($ per BOE of gross production)
Average production (lifting) cost of conventional
(1)
crude oil and gas
Note:
(1)
Production (lifting) costs include all expenses related to the operation and maintenance of producing or producible wells
and related facilities, natural gas plants and gathering systems, and Firebag central facilities. It does not include an
estimate for future asset retirement costs. These costs represent a blended average of our Firebag and Natural Gas lifting
costs.
Producing Oil and Gas Wells
As at December 31, 2007
Crude Oil(3)
Natural Gas
Total
number of wells
Alberta
British Columbia
Total
Gross(1)
Net(2)
Gross(1)
Net(2)
Gross(1)
Net(2)
71
19
90
56
8
64
399
143
542
238
65
303
470
162
632
294
73
367
Notes:
(1)
Gross wells are the total number of wells in which an interest is owned.
(2)
Net wells are the sum of fractional interests owned in gross wells.
(3)
Well information includes Firebag.
27
Oil and Gas Acreage
As at December 31, 2007
(thousands of acres)
Undeveloped(1)
Gross(1)
Net(2)
Developed
Gross(1)
Net(2)
Canada
Natural Gas
Firebag
Total Canada
USA
Natural Gas
Total
Total
Gross(1)
Net(2)
690
2
692
410
2
412
1,250
287
1,537
680
287
967
1,940
289
2,229
1,090
289
1,379
692
412
46
1,583
24
991
46
2,275
24
1,403
Notes:
(1)
Undeveloped acreage is considered to be those on which wells have not been drilled or completed to a point that would
permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage
contains proved reserves. Gross acres mean all the acres in which we have either an entire or undivided percentage
interest.
(2)
Net acres represent the acres remaining after deducting the undivided percentage interest of others from the gross acres.
Drilling Activity
For the year ended December 31, 2007
(number of net wells)
Productive
Canada
Natural Gas
Firebag
United States
Total
7
7
Net Exploratory
Dry Holes
Net Development
Productive
Dry Holes
Total
4
4
11
11
14
26
40
Total
1
1
15
26
41
For the year ended December 31, 2006
(number of net wells)
Productive
Canada
Natural Gas
Firebag
United States
Total
3
3
Net Exploratory
Dry Holes
Net Development
Productive
Dry Holes
Total
6
6
9
9
14
8
22
Total
4
4
18
8
26
For the year ended December 31, 2005
(number of net wells)
Productive
Net Exploratory
Dry Holes
Net Development
Productive
Dry Holes
Total
Total
Canada
Natural Gas
Firebag
United States
8
-
3
1
11
1
18
10
-
4
-
22
10
-
Total
8
4
12
28
4
32
At December 31, 2007, we were participating in the drilling of 28 gross (16 net) exploratory and
development wells.
28
Future Commitments to Sell or Deliver Crude Oil and Natural Gas
We have entered into a number of natural gas sale commitments aggregating approximately 64
mmcf/day. These sales commitments consist of both short-and long-term contracts ranging from one
year and for one agreement, for the life of a specified production field. All production comes from our
reserves. All pricing under these agreements is based upon both a combination of variable, fixed and
index-based terms.
As at March 4, 2008 crude oil hedges totaling 10,000 bpd of production were outstanding for the
remainder of 2008. Prices for these barrels are fixed within a range of US$59.85 to US$101.06 per
barrel. In addition, we have also purchased $60 USD WTI put options for calendar years 2009 and 2010
for volumes of 55,000 bpd. We intend to consider additional costless collars of up to approximately 30%
of our crude oil planned production if strategic opportunities are available. For further particulars of these
arrangements, see the information under the heading "Derivative Financial Instruments", under "Risk
Factors Affecting Performance" in the "Suncor Corporate Overview and Strategic Priorities" section of our
MD&A, and Note 7 to our 2007 Consolidated Financial Statements, which note is incorporated by
reference herein.
VOLUNTARY OIL SANDS RESERVES AND RESOURCES DISCLOSURE
Oil Sands Mining and Firebag In-Situ Reserves Reconciliation
The following tables set out, on a gross7 and net basis, a reconciliation of our proved and probable
reserves of synthetic crude oil from our Oil Sands mining leases and bitumen, converted to synthetic
crude oil for comparison purposes only, from our in-situ Firebag leases, from December 31, 2006, to
December 31, 2007, based on the GLJ Oil Sands Reports.
Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation
Proved
Probable
Proved &
Probable
Proved(3)
Probable(3)
Proved &
Probable
Total
Mining and
In-situ(3)
Proved &
Probable
1,709
(1)
634
106
2,343
105
803
(17)
1,907
(5)
2,710
(22)
5,053
83
(74)
1,634
740
(74)
2,374
80
(11)
855
(66)
1,836
14
(11)
2,691
14
(85)
5,065
Oil Sands Mining Leases
(millions of barrels of synthetic
(1)
crude oil)
December 31, 2006
Revisions of previous
estimates
Improved recovery
Extensions and discoveries
Production
December 31, 2007
7
(1)(2)
(1)(3)
Firebag In-situ Leases
Suncor's working interest in reserves, before deducting Crown royalties, freehold and overriding royalty interests.
29
Estimated Net Proved and Probable Oil Sands Reserves Reconciliation
Oil Sands Mining Leases
(millions of barrels of synthetic
(1)
crude oil)
December 31, 2006
Revisions of previous
estimates
Improved recovery
Extensions and discoveries
Production
December 31, 2007
(1)(2)
(1)(3)
Firebag In-situ Leases
Total
Mining and
(3)
In-situ
Proved
Probable
Proved &
Probable
Proved(3)
Probable(3)
Proved &
Probable
Proved &
Probable
1,507
11
564
108
2,071
119
722
(15)
1,639
(7)
2,361
(22)
4,432
97
(66)
1,452
672
(66)
2,124
72
(11)
768
(60)
1,572
12
(11)
2,340
12
(77)
4,464
Notes:
(1)
Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 78.5% for proven
reserves, and 80% for proved plus probable reserves under Oil Sands mining leases and 80% for both proved reserves
and proved plus probable reserves for Firebag in-situ leases. Virtually all of our bitumen from the Oil Sands mining leases
is upgraded into synthetic crude oil. However, we have the option of selling the bitumen produced from our Firebag in-situ
leases directly to the market where strategic opportunities exist. Accordingly, these bitumen reserves are converted to
synthetic crude oil for aggregation purposes.
(2)
Our gross mining reserves are evaluated in part, based on the current mine plan and estimates of extraction recovery and
upgrading yields, rather than an analysis based on constant dollar or forecast pricing assumptions. Net mining reserves
reflect the relative value of Crown, freehold and overriding royalty burdens based on 2007 Annual Average Differential
Pricing assumptions in accordance with CSA Staff Notice 51-315 and reflects our exercised option to elect to transfer to a
bitumen-based Crown royalty effective at the beginning of 2009. Neither the current proposed Alberta royalty regime
changes, nor our Royalty Amending Agreement have been incorporated.
(3)
Under "Required U.S. Oil and Gas and Mining Disclosure", we reported proved reserves from our Firebag in-situ leases.
The disclosure in the table above reports proved reserves from these leases and differs in the following four ways.
Reserves from our Firebag in-situ leases under our voluntary disclosure:
(a)
are disclosed on a gross basis as well as the required net basis under U.S. disclosure requirements;
(b)
are converted from barrels of bitumen to barrels of synthetic crude oil in this table for aggregation purposes;
(c)
include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements.
U.S. companies do not disclose probable reserves for non-mining properties. We voluntarily disclose our
probable reserves for Firebag in-situ leases as we believe this information is useful to investors, and allows us
to aggregate our mining and our in-situ reserves into a consolidated total for our Oil Sands business. As a
result, our Firebag in-situ estimates in the above tables are not comparable to those made by U.S. companies.
(d)
are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff
Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.
Remaining Recoverable Resources
Suncor holds a 100% interest in its oil sands leases, all located near Fort McMurray in the Athabasca
region of Alberta. Based upon independent evaluations conducted by GLJ effective December 31, 2007,
our best estimate of remaining recoverable synthetic crude oil resources, and the components included in
the summation, are as follows (billions of barrels):
Mining
Proved plus probable reserves
Best estimate contingent resources
Best estimate remaining recoverable resources
2.4
4.2
6.6
In-Situ
2.6
6.3
8.9
Total
5.0
10.5
15.5
The Contingent resources are not classified as reserves due to the absence of a commercial
development plan that includes a firm intent to develop within a reasonable timeframe, and in some cases
30
due to higher uncertainty as a result of lower core-hole drilling density. Our Voyageur South development
area, for which we submitted a regulatory application in 2007, is part of our mining contingent resources.
Significant mining contingent resources are also associated with our Audet leases, locate north of our
Firebag leases and immediately adjacent to leases proposed for mining development by other operators.
All of our in-situ leases are associated with our Firebag leases. While we consider the contingent
resources to be potentially recoverable under reasonable economic and operating conditions, there is no
certainty that it will be commercially viable to produce any portion of them.
SUNCOR EMPLOYEES
The following table shows the distribution of employees among our three business units and corporate
office for the past two years.
as at
December 31,
2007
2006
Oil Sands .......................................................................................................
Natural Gas....................................................................................................
Refining & Marketing......................................................................................
Corporate(2) ....................................................................................................
Total (1) ...........................................................................................................
3,612
159
1,151
1,543
6,465
3,182
170
1,068
1,346
5,766
Notes:
(1)
In addition to our employees, we also use independent contractors to supply a range of services.
(2)
Corporate employees includes employees from our Major Projects group, which supports all three of our business units.
The Communications, Energy and Paperworkers Union Local 707 represent approximately 2,100 Oil
Sands employees. A new collective agreement with the union was entered into effective May 1, 2007.
The terms of the agreement include a wage increase of 7% in the first year and 6% in each of the
following two years, as well as an initial lump sum payment.
Employee associations represent approximately 220 of R&M - Canada’s Sarnia refinery, London terminal
and Sun-Canadian Pipe Line Company employees. During 2005, a three year agreement was signed
with the Sarnia employee association that will be renegotiated in 2008. During 2006, a three year
agreement was signed with the CAW at the London terminal that will continue year after year unless
either party provides written notice at least 30 days prior to the expiry date of the agreement of their intent
to terminate or negotiate revisions. Management believes the agreement will be renegotiated on its
anniversary. The agreement with the employee association of Sun-Canadian Pipe Line Company was
signed in 1993, and it is renewed automatically each year unless terminated by written notice by either
party at least 60 days prior to the anniversary date of the agreement. No notice under such agreement
has been received or given to date. Management believes the agreement will be automatically renewed
on its anniversary.
The United Steel Workers (USW) union represents approximately 218 employees at R&M’s Denver
refining facilities. In February 2006, the union voted to merge all workers into a single collective
bargaining agreement. The merged contract became effective in March 2006 and will expire in January
2009.
31
RISK FACTORS
As a company, we identify risks in four principal categories: 1) Operational; 2) Financial; 3) Legal and
Regulatory; and 4) Strategic. These categories are defined below, and identified risks have been
classified accordingly. Please note, identified risks could relate to multiple risk categories; we have
classified risks based on the primary category to which they apply to Suncor.
We are continually working to mitigate the impact of potential risks to our business. This process includes
an entity-wide risk review. The internal review is completed annually to help ensure that all significant
risks are identified and appropriately managed. Risks appear in no particular order below:
1)
Operational Risks – Risks that directly affect our ability to continue normal operations
within our identified businesses.
Confidentiality. Breach of confidentiality could place us at competitive risk if confidential operational
information or proprietary intellectual property was improperly disclosed.
Operating Hazards and Other Uncertainties. Each of our three principal operating businesses, Oil Sands,
NG, and R&M require high levels of investment and have particular economic risks and opportunities.
Generally, our operations are subject to hazards and risks such as fires, explosions, gaseous leaks,
migration of harmful substances, blowouts, power outages and oil spills, any of which can cause personal
injury, damage to property, IT systems and related data and control systems, equipment and the
environment, as well as interrupt operations. In addition, all of our operations are subject to all of the
risks normally incident to transporting, processing and storing crude oil, natural gas and other related
products. Risks associated with access to skilled labour to support our operations in a safe and effective
manner are also discussed in “Labour and Materials Supply”, below.
At Oil Sands, mining oil sands and producing bitumen through in-situ methods, extracting bitumen from
the oil sands, and upgrading bitumen into synthetic crude oil and other products involves particular risks
and uncertainties. Oil Sands is susceptible to loss of production, slowdowns, shutdowns, or restrictions
on our ability to produce higher value products due to the interdependence of its component systems.
Severe climatic conditions at Oil Sands can cause reduced production during the winter season and in
some situations can result in higher costs. While there is virtually no finding costs associated with oil
sands resources, delineation of the resources, the costs associated with production, including mine
development and drilling wells for SAGD operations, and the costs associated with upgrading bitumen
into synthetic crude oil can entail significant capital outlays. The costs associated with production at Oil
Sands are largely fixed in the short term and, as a result, operating costs per unit are largely dependent
on levels of production.
There are risks and uncertainties associated with NG’s operations, including all of the risks normally
incident to drilling for natural gas wells, the operation and development of such properties, including
encountering unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs,
equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas
or well fluids, adverse weather conditions, pollution and other environmental risks.
Our downstream business is subject to all of the risks normally inherent in the operation of a refinery,
terminals, pipelines and other distribution facilities as well as service stations, including loss of product,
slowdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock or other
accidents.
We are also subject to operational risks such as sabotage, terrorism, trespass, related damage to remote
facilities, theft and malicious software or network attacks.
Major Projects. There are certain risks associated with the execution of our major projects, including
without limitation, the new coker unit and the Voyageur growth strategy. These risks include: our ability to
obtain the necessary environmental and other regulatory approvals; risks relating to schedule, resources
and costs, including the availability and cost of materials, equipment and qualified personnel; the impact
32
of general economic, business and market conditions; the impact of weather conditions; our ability to
finance growth if commodity prices were to decline and stay at low levels for an extended period; and the
effect of changing government regulation and public expectations in relation to the impact of oil sands
development on the environment. The commissioning and integration of new facilities with the existing
asset base could cause delays in achieving targets and objectives. Management believes the execution
of major projects presents issues that require prudent risk management. There are also risks associated
with project cost estimates provided by us. Some cost estimates are provided at the conceptual stage of
projects and prior to commencement or completion of the final scope design and detailed engineering
needed to reduce the margin of error. Accordingly, actual costs can vary from estimates and these
differences can be material.
Cost estimates for major projects involve uncertainties and evolve in stages. For a discussion of our
significant capital projects in progress, see page 18 of our MD&A, incorporated by reference herein.
Insurance. Although we maintain a risk management program, which includes an insurance component,
such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable.
Losses beyond the scope of insurance could have a material adverse impact on the company. In late
2005 we formed a self-insurance entity to provide additional business interruption coverage for potential
losses. In 2006, one of our external business interruption service providers discontinued operations. We
continue to evaluate options to replace this coverage. Refer to note 11 to our 2007 Consolidated
Financial Statements, which is incorporated by reference herein, for further description of our insurance
coverage.
In December 2006, insurers impacted by the January 4, 2005 fire at Oil Sands filed a statement of claim
against various parties alleged to be potentially responsible, seeking to recover amounts paid to Suncor
under our insurance contract. As required by our insurance contract, we are named as Plaintiff.
However, the action will not have an impact on the insurance settlements we have already reached with
our insurers or on our future revenues.
2)
Financial Risks – Risks that affect the compilation, reporting and accuracy of financial
results.
Uncertainty of Reserve Estimates. The reserves estimates for our Oil Sands and NG business units
included in this AIF represent estimates only. There are numerous uncertainties inherent in estimating
quantities and quality of these proved and probable reserves and resources, including many factors
beyond our control.
In general, estimates of economically recoverable reserves are based upon a number of variable factors
and assumptions, such as historical production from the properties, the assumed effect of regulation by
governmental agencies, pricing assumptions, future royalties and future operating costs, yield rates for
production of synthetic crude oil from bitumen, all of which may vary considerably from actual results.
The accuracy of any reserve estimate is a matter of engineering interpretation and judgment and is a
function of the quality and quantity of available data, which may have been gathered over time. In the Oil
Sands business unit, reserve and resource estimates are based upon a geological assessment, including
drilling and laboratory tests, and also consider current production capacity and upgrading yields, current
mine plans, operating life and regulatory constraints. The Firebag reserves and resource estimates are
based upon a geological assessment of data gathered from evaluation drilling, the testing of core
samples and seismic operations and demonstrated commercial success of the in-situ process. Our actual
production, revenues, royalties, taxes and development and operating expenditures with respect to our
reserves will vary from such estimates, and such variances could be material. Production performance
subsequent to the date of the estimate may justify revision, either upward or downward, if material. For
these reasons, estimates of the economically recoverable reserves attributable to any particular group of
properties, and classification of such reserves based on risk of recovery, prepared by different engineers
or by the same engineers at different times, may vary substantially.
Volatility of Crude Oil and Natural Gas Prices. Our future financial performance is closely linked to crude
oil prices, and to a lesser extent, natural gas prices. The prices of these commodities can be influenced
33
by global and regional supply and demand factors. Worldwide economic growth, political developments,
compliance or non-compliance with quotas imposed upon members of the Organization of the Petroleum
Exporting Countries and weather, among other things, can affect world oil supply and demand. Our
natural gas price realizations are affected primarily by North American supply and demand and by prices
of alternate sources of energy. All of these factors are beyond our control and can result in a high degree
of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials
between heavy and light grades of crude oil, which can impact prices for sour crude oil and bitumen. Oil
and natural gas prices have fluctuated widely in recent years and we expect continued volatility and
uncertainty in crude oil and natural gas prices. A prolonged period of low crude oil and natural gas prices
could affect the value of our crude oil and gas properties and the level of spending on growth projects,
and could result in curtailment of production on some properties. Accordingly, low crude oil prices in
particular could have an adverse impact on our financial condition and liquidity and results of operations.
A key component of our business strategy is to produce sufficient natural gas to meet or exceed internal
demands for natural gas purchased for consumption in our operations, creating a price hedge which
reduces our exposure to gas price volatility. However, there are no assurances that we will be able to
continue to increase production to keep pace with growing internal natural gas demands.
Under our strategic crude oil hedging program, management has approval to fix a price or range of prices
for approximately 30% of our total crude oil planned production for specified periods of time. As at March
4, 2008, we had crude oil hedges totaling 10,000 bpd of crude oil for production in 2008. Prices for these
barrels are fixed within a range from an average of US$59.85/bbl up to an average of US$101.06/bbl. In
addition, we have also purchased $60 USD WTI put options for calendar years 2009 and 2010 for
volumes of 55,000 bpd. We intend to consider additional strategic hedging opportunities as they become
available.
We conduct an assessment of the carrying value of our assets to the extent required by Canadian
generally accepted accounting principles. If crude oil and natural gas prices decline, the carrying value of
our assets could be subject to downward revisions, and our earnings could be adversely affected.
Volatility of Downstream Margins. Our downstream business is sensitive to wholesale and retail margins
for its refined products, including gasoline, and asphalt. Margin volatility is influenced by overall
marketplace competitiveness, weather, the cost of crude oil (see "Volatility of Crude Oil and Natural Gas
Prices") and fluctuations in supply and demand for refined products. We expect that margin and price
volatility and overall marketplace competitiveness, including the potential for new market entrants, will
continue. As a result, our operating results for R&M can be expected to fluctuate and may be adversely
affected.
In the Western Canadian diesel fuel market, demand and supply can fluctuate. Margins for diesel fuel are
typically higher than the margins for synthetic and conventional crude oil. The below noted expansion
plans of our competitors could result in an increase in the supply of diesel fuel and weaken margins.
Energy Trading Activities. The nature of trading activities creates exposure to financial risks. These
include risks that movements in prices or values will result in a financial loss to the company; a lack of
counterparties will leave us unable to liquidate or offset a position, or unable to do so at or near the
previous market price; we will not receive funds or instruments from our counterparty at the expected
time; the counterparty will fail to perform an obligation owed to us; we will suffer a loss as a result of
human error or deficiency in our systems or controls; or we will suffer a loss as a result of contracts being
unenforceable or transactions being inadequately documented. A separate risk management function
within the company develops and monitors practices and policies and provides independent verification
and valuation of our trading and marketing activities. However, we may experience significant financial
losses as a result of these risks.
Exchange Rate Fluctuations. Our 2007 Consolidated Financial Statements are presented in Canadian
dollars. Results of operations are affected by the exchange rates between the Canadian dollar and the
U.S. dollar. These exchange rates have varied substantially in the last five years. A substantial portion of
our revenue is received by reference to U.S. dollar denominated prices and a significant portion of our
debt is denominated in U.S. dollars. Crude oil and natural gas prices are generally based in U.S. dollars,
34
while a portion of our sales of refined products are in Canadian dollars. In addition, we have subsidiary
operations that are denominated in U.S. dollars, translated to Canadian dollars using the current rate
approach, whereby revenues and expenses are recorded at the exchange rate at the time the transaction
occurs, and assets and liabilities are translated at the exchange rate at the balance sheet date.
Therefore, fluctuations in exchange rates between the U.S. and Canadian dollar may give rise to foreign
currency exposure, either favorable or unfavorable, creating another element of uncertainty.
Interest Rate Risk. We are exposed to fluctuations in short-term Canadian interest rates as a result of the
use of floating rate debt. We maintain a substantial portion of our debt capacity in revolving, floating rate
bank facilities and commercial paper, with the remainder issued in fixed rate borrowings. To minimize our
exposure to interest rate fluctuations, we occasionally enter into interest rate swap agreements and
exchange contracts to either effectively fix the interest rate on floating rate debt or to float the interest rate
on fixed rate debt. For more details, see the "Liquidity and Capital Resources" section of our MD&A.
3)
Legal and Regulatory Risks – Risks that affect our ability to comply with regulatory and
statutory requirements under applicable law.
Environmental Regulation and Risk. Environmental regulation affects nearly all aspects of our
operations. These regulatory regimes are laws of general application that apply to us in the same
manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes
require us to obtain operating licenses and permits in order to operate, and impose certain standards and
controls on activities relating to mining, oil and gas exploration, development and production, and the
refining, distribution and marketing of petroleum products and petrochemicals.
Environmental
assessments and regulatory approvals are required before initiating most new major projects or
undertaking significant changes to existing operations. In addition to these specific, known requirements,
we expect future changes to environmental legislation, including anticipated legislation for air pollution
(Criteria Air Contaminants) and greenhouse gases, that will impose further requirements on companies
operating in the energy industry.
Some of the issues that are or may in future be subject to environmental regulation include:
*
the possible cumulative impacts of oil sands development in the Athabasca region and the
province;
*
storage, treatment, and disposal of hazardous or industrial waste;
*
the need to reduce or stabilize various emissions to air and withdrawals of and discharges to
water;
*
issues relating to global climate change, land reclamation and restoration;
*
issues relating to the manufacture or use of certain substances;
*
reformulated gasoline to support lower vehicle emissions.
Changes in environmental regulation could have an adverse effect on us from the standpoint of product
demand, product reformulation and quality, methods of production and distribution costs, and financial
results. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred,
which may or may not be recoverable in the marketplace. The complexity and breadth of these issues
make it extremely difficult to predict their future impact on us. Management anticipates capital
expenditures and operating expenses could increase in the future as a result of the implementation of
new and increasingly stringent environmental regulations. Compliance with environmental regulation can
require significant expenditures and failure to comply with environmental regulation may result in the
imposition of fines and penalties, liability for clean up costs and damages and the loss of important
permits.
35
Suncor is making progress to address challenges at its in-situ operation, where high emissions have
resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. Until
regulators can be assured emissions are stable at compliant levels, production at the in-situ operation has
been capped at approximately 42,000 barrels of bitumen per day. As a result, commissioning of units to
increase the bitumen production capacity of Firebag Stages 1 and 2 by about 35% will be delayed.
Suncor’s revised outlook reflects this constraint. However, unexpected problems in connection with
installation of emission abatement equipment, or unanticipated changes to permits or changes to
regulatory requirements may adversely affect our plans for increasing bitumen production capacity of
Firebag. Furthermore, we may be subject to further regulatory enforcement action, which may in turn,
have an adverse effect on our business.
To mitigate the impact to production, we are examining ways to increase bitumen supply from our mining
operations. We are also accelerating the construction of emission abatement equipment, which will result
in additional maintenance and capital costs being incurred.
In December 2007, high emissions at our base plant resulted in an order being issued by Alberta
Environment. Emissions at the oil sands plant exceeded air quality standards, and accordingly we are
upgrading our emission control equipment and reducing discharges to the tailings ponds. In addition, we
have introduced processing changes and are undertaking a more comprehensive monitoring program.
However, unexpected problems in connection with upgrading our emission control equipment or
introducing process changes, or unanticipated changes to permits or changes to regulatory requirements
may adversely affect our plans for decreasing emissions at base plant. Any such unexpected problems
may lead to further regulatory enforcement action, which may in turn, have an adverse effect on our
business.
For Suncor’s Oil Sands mining leases 86 and 17, we are required to and have posted annually with
Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced as of
December 31, 2006 ($14 million as at December 31, 2006) as security for the estimated cost of our
reclamation activity. Since there was no production from Leases 86/17 in 2006 or 2007, the amount of
security remains unchanged.
For the Millennium, Steepbank, and North Steepbank mines, we have posted irrevocable letters of credit
equal to approximately $227 million with Alberta Environment, representing security for the maximum
reclamation liability in the period April 1, 2007 through March 31, 2008. For more information about our
reclamation and environmental remediation obligations, refer to “Tailings Management” under “Risk
Factors Affecting Performance” and "Asset Retirement Obligations" under "Critical Accounting Estimates"
in our MD&A.
A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta. The
MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets
against MLMP liabilities and measurement of reserve life. Partial security could be required if reclamation
targets are not met and full security may eventually be required.
Over the past few years legislation has been passed in Canada and the United States to reduce
allowable levels of sulphur in transportation fuels. For a discussion of projects completed at our R&M
operations, see the information under the R&M section of "Narrative Description of the Business", in this
AIF. Projects to retrofit existing facilities to comply with these standards are subject to all risks inherent in
large capital projects, and to the additional risk that failure to meet legislated deadlines could have a
material impact on the Company’s ability to market its products, or subject the Company to fines and
penalties potentially having a material impact on revenues and earnings.
The R&M U.S. operations is subject to Consent Decrees with the United States Environmental Protection
Agency, the United States Department of Justice and the State of Colorado. For a discussion of these
consent decrees and the related obligations, see the information under the R&M section of “Three Year
History” in this AIF. The Company is subject to the risk that failure to meet remaining obligations or the
deadlines under these Consent Decrees could have a material impact on the Company’s ability to market
its products, potentially having a material impact on revenues and earnings.
36
In addition, our business could be affected by the potential for lawsuits against greenhouse gas emitters,
based on links drawn between greenhouse gas emissions and climate change.
Governmental Regulation. The oil and gas industry in Canada and the United States, including the oil
sands industry and our downstream segments, operates under federal, provincial, state and municipal
legislation. This industry is also subject to regulation and intervention by governments in such matters as
land tenure, royalties, taxes (including income taxes), government fees, production rates, environmental
protection controls, the reduction of greenhouse gas and other emissions, the export of crude oil, natural
gas and other products, the awarding or acquisition of exploration and production, oil sands or other
interests, the imposition of specific drilling obligations, control over the development and abandonment of
fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of
contract rights. Before proceeding with most major projects, including significant changes to existing
operations, we must obtain regulatory approvals. The regulatory approval process can involve
stakeholder consultation, environmental impact assessments and public hearings, among other things. In
addition, regulatory approvals may be subject to conditions including security deposit obligations and
other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis on
satisfactory terms, could result in delays, abandonment or restructuring of projects and increased costs,
all of which could negatively affect future earnings and cash flow. Such regulations may be changed from
time to time in response to economic or political conditions. The implementation of new regulations or the
modification of existing regulations affecting the crude oil and natural gas industry could reduce demand
for crude oil and natural gas, increase our costs and have a material adverse effect on our financial
condition.
Land Claims. First Nations peoples have claimed aboriginal title and rights to a substantial portion of
Western Canada. In addition, First Nations peoples have filed claims against industry participants
generally, relating in part to land claims which may affect our Natural Gas business. We are unable to
assess the effect, if any, these or other claims, may have on our Oil Sands or other operations.
Alberta Crown Royalties. The following risk factors could cause royalty expenses to differ materially from
current estimates and impact the royalties payable to the Crown:
•
Pursuant to the new royalty framework, the government intends to establish a permanent generic
“bitumen valuation methodology” (BVM) for determining the “R” related to bitumen. The Crown is
consulting with stakeholders and independent advisors with a decision on the methodology
anticipated by June 30, 2008 and final determination of such methodology may have an impact on
royalties payable to the Crown.
•
The government also announced its intention to assess and recommend improvements in the system,
structures and resources supporting the collection, verification and reporting of provincial royalties.
This assessment is expected to be completed by March 31, 2008 and steps taken by the government
thereafter may affect the calculation of royalties; and
•
Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital
and operating costs for each oil sands project; changes to the Generic Regime by the Government of
Alberta; changes in other legislation; and the occurrence of unexpected events.
4)
Strategic Risks – Risks that affect our ability to meet long term goals and planning
initiatives.
Interdependence of Oil Sands Systems. The Oil Sands plant is susceptible to loss of production due to
the interdependence of its component systems. Through growth projects, we expect to further mitigate
adverse impacts of interdependent systems and to reduce the production and cash flow impacts of
complete plant-wide shutdowns. For example, we added a second upgrader which provides us with the
flexibility to conduct periodic plant maintenance on one operation while continuing production and cash
flow generation from the other.
37
Dependence on Oil Sands Business. The Company's significant capital commitment to further our growth
projects at Oil Sands, including Voyageur, may require us to forego investment opportunities in other
segments of our operations. The completion of future projects to increase production at Oil Sands will
further increase our dependence on the Oil Sands segment of our business. For example, in 2007, the
Oil Sands business accounted for approximately 87% (88% in 2006) of our upstream production, 87%
(89% in 2006) of our net earnings and 79% (84% in 2006) of our cash flow from operations. These
percentages have been determined excluding the corporate and eliminations segment information.
Need to Replace Conventional Natural Gas Reserves. Future natural gas reserves and production of the
Company's NG business unit are highly dependent on our success in discovering or acquiring additional
reserves and exploiting our current reserve base. This impacts our ability to maintain a price hedge
against the growing consumption of natural gas in our operations. Without natural gas reserve additions
through exploration and development or acquisition activities, our conventional natural gas reserves and
production will decline over time as reserves are depleted. For example, in 2007, our average natural
gas reservoir decline rate was approximately 24% (2006 – 24%). Decline rates will vary with the nature of
the reservoir, life-cycle of the well and other factors. Therefore, historical decline rates are not
necessarily indicative of future performance. Exploring for, developing and acquiring reserves is highly
capital intensive. To the extent cash flow from operations8 is unable to generate sufficient capital and
external sources of capital become limited or unavailable, our ability to make the necessary capital
investments to maintain and expand our conventional natural gas reserves could be impaired. In
addition, the long term performance of the NG business is dependent on our ability to consistently and
competitively find and develop low cost, high-quality reserves that can be economically brought on
stream. Market demand for land and services can also increase or decrease finding and development
costs. There can be no assurance that we will be able to find and develop or acquire additional reserves
to replace production at acceptable costs.
Competition. The petroleum industry is highly competitive in all aspects, including the exploration for, and
the development of, new sources of supply, the acquisition of crude oil and natural gas interests and the
refining, distribution and marketing of petroleum products and chemicals. We compete in virtually every
aspect of our business with other energy companies. The petroleum industry also competes with other
industries in supplying energy, fuel and related products to consumers. We believe the competition for
our crude oil production is other North American conventional and synthetic sweet and sour crude oil
producers. With current expansion plans, there are risks associated with the delivery of our products to
market.
A number of other companies have entered or have indicated they are planning to enter the oil sands
business and begin production of bitumen and synthetic crude oil or expand their existing operations. It is
difficult to assess the number, level of production and ultimate timing of all of the potential new projects or
where existing production levels may increase. Based on management's knowledge of other projects
derived from publicly available information, Canada’s production of bitumen and upgraded synthetic crude
oil could increase from approximately one million bpd in 2004 to approximately two million bpd by 20109.
Increasing industry consolidation, a global focus on oil sands and additional competitors with financial
capacity has: i) materially increased the supply of bitumen and synthetic crude oil and other competing
crude oil products in the marketplace; ii) exponentially increased land values and availability of new
leases; and iii) placed stress on the availability and cost of all resources required to run the Oil Sands
operation. If we are unable to transport our produced crude oil products, production levels may be
adversely affected.
Historically, the industry-wide oversupply of refined petroleum products and the overabundance of retail
outlets have kept downward pressure on downstream refining and retail margins. Management expects
that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness
will continue. In addition, to the extent that our downstream business unit participates in new product
markets, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations.
8
9
Refer to "Non GAAP Financial Measures" on page ix of this AIF.
Alberta Government – Talk About Oil Sands
38
Labour and Materials Supply. With the expansion of the industry and the impact of new entrants to the
business, risks in the form of availability of/competition for skilled labour and materials supply continue to
build. Although these risks are not exclusive to our Oil Sands operation, the increased demands on the
Fort McMurray, Alberta infrastructure (for example, housing, roads, medical facilities, and schools) and a
commuting workforce have heightened concerns. Our ability to operate safely and effectively and
complete major projects on time and on budget is significantly impacted by these risks. Risks associated
with completion of significant capital projects are discussed in “Major Projects” above.
Pipeline Capacity Constraints. With our current expansion plans, combined with several other major
capital initiatives scheduled by others in the industry, there are increasing risks associated with pipeline
capacity and infrastructure which may negatively affect our sales mix and production levels. This is
already evident in the timing and method of delivery of our crude oil products to market, as well as our
ability to produce at capacity levels in our NG business.
Technology Risk. There are risks associated with growth and other capital projects that rely largely or
partly on new technologies and the incorporation of such technologies into new or existing operations.
The success of projects incorporating new technologies, such as in-situ technology, cannot be assured.
In-situ Extraction. Current steam-assisted gravity drainage (SAGD) technologies for in-situ recovery of
heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other
fuels in the production of steam which is used in the recovery process. The amount of steam required in
the production process can also vary and impact costs. The performance of the reservoir can also impact
the timing and levels of production using this technology. Commercial application of this technology is not
yet commonplace and accordingly, in the absence of operating history, there can be no assurances with
respect to the sustainability of SAGD operations.
Reclamation. There are risks associated with our ability to complete reclamation work, specifically
reclaiming tailings ponds which contain water, clay and residual bitumen produced through the extraction
process. To reclaim tailings ponds, we are using a process referred to as consolidated tailings (CT)
technology. At this time, no ponds have been fully reclaimed using this technology. The success of the
CT technology and time to reclaim the tailings ponds could increase or decrease the current asset
retirement cost estimates. We continue to monitor and assess other possible technologies and/or
modifications to the consolidated tailings process now being used. Regulatory approval of our North
Steepbank mine extension, planned for operation in 2010, is subject to certain conditions related to the
performance of CT technology.
Labour Relations. Hourly employees at our Oil Sands facility near Fort McMurray, Alberta, our London,
Ontario terminal operation, our Sarnia, Ontario refinery, our Denver, Colorado refinery and at SunCanadian Pipeline Company are represented by labour unions or employee associations. Any work
interruptions involving our employees, and/or contract trades utilized in our projects or operations, could
materially and adversely affect our business and financial position.
U.S. Policies re: Clean Oil. Recently, certain U.S. governmental agencies have indicated their intention to
purchase oil and related refined products from conventional sources, rather than from the oil sands, which
in their view, is a less environmentally friendly source of oil. Although we continue to focus on mitigating
our business impact to air, water and land, widespread implementation of such policies could adversely
affect markets for our products.
39
SELECTED CONSOLIDATED FINANCIAL INFORMATION
Selected Consolidated Financial Information
The following selected consolidated financial information for each of the years in the three-year period
ended December 31, 2007, is derived from our 2007 Consolidated Financial Statements. Our
consolidated financial statements for each of the years in the three-year period ended December 31,
2007 have been audited by PricewaterhouseCoopers LLP, Chartered Accountants. The information set
forth below should be read in conjunction with our MD&A and our 2007 Consolidated Financial
Statements.
($ millions except per share amounts)
2007
Revenues .....................................................................
Net earnings.................................................................
Per common share (undiluted) ..................................
Per common share (diluted) ......................................
Cash flow from operations ...........................................
Capital and exploration expenditures ...........................
17,933
2,832
6.14
6.02
3,805
5,415
($ millions)
2007
Total assets..................................................................
Long-term debt.............................................................
Accrued liabilities and other(1) ......................................
Shareholders' equity ....................................................
24,167
3,811
1,434
11,613
Year ended December 31,
2006
15,829
2,971
6.47
6.32
4,533
3,613
2005
11,129
1,158
2.54
2.48
2,476
3,153
As at December 31,
2006
18,759
2,363
1,214
8,952
2005
15,126
2,984
1,005
5,996
Note:
(1)
See Note 8 to our 2007 Consolidated Financial Statements, which is incorporated by reference herein.
The following table sets forth, for each of the two most recently completed financial years, the revenues
for each category of our principal products or services that accounted for 15 per cent or more of our total
consolidated revenues.
Revenues from:
($ millions)
Transportation fuel sales
Crude oil sales
Energy marketing and trading
(2)
Other
Total
2007
8,056
5,124
2,883
1,840
17,903
(1)
%
45
29
16
10
100
2006
7,016
5,199
1,582
2,019
15,816
(1)
%
44
33
10
13
100
Notes:
(1)
(2)
Excludes interest income.
Includes net insurance proceeds of $436 million in 2006 (2007 - nil)
Dividend Policy and Record
Our Board of Directors has established a policy of paying dividends on a quarterly basis. We review our
policy from time to time in light of our financial position, financing requirements for growth, cash flow and
other factors which our Board of Directors considers relevant. Our Board of Directors approved an
increase in the quarterly dividend to $0.10 per share from $0.08 per share in the second quarter of 2007,
and an increase to $0.08 per share from $0.06 per share during the second quarter of 2006.
40
The following table sets forth the per share amount of dividends we paid to shareholders during the last
three years.
Year Ended December 31,
2006
2007
2005
Common Shares
cash dividends.........................................................
$0.38
$0.30
$0.24
Dividends paid in common shares...............................
-
-
-
MANAGEMENT'S DISCUSSION AND ANALYSIS
Our MD&A, dated February 27, 2008, is incorporated by reference herein and forms an integral part of
this AIF, and should be read in conjunction with our 2007 Consolidated Financial Statements and the
notes thereto.
DESCRIPTION OF CAPITAL STRUCTURE
General Description of Capital Structure
Our authorized capital consists of an unlimited number of common shares without nominal or par value
and an unlimited number of preferred shares without nominal or par value, issuable in series. As at
December 31, 2007, a total of 462,782,806 common shares were issued and outstanding and no
preferred shares had been issued.
Each common share entitles the holder to receive notice of and to attend all meetings of our
shareholders, other than meetings at which only the holders of another class or series are entitled to vote.
Each common share entitles the holder to one vote. The holders of common shares, in the discretion of
the Board of Directors, are entitled to receive out of any monies properly applicable to the payment of
dividends, and after the payment of any dividends payable on preferred shares (if any), of any series or
any other series ranking prior to the common shares as to the payment of dividends, any dividends
declared and payable on the common shares. Upon any liquidation, dissolution or winding-up of Suncor,
or other distribution of our assets among our shareholders for the purposes of winding-up our affairs, the
holders of the common shares are entitled to share on a share-for-share basis in the distribution, except
for the prior rights of the holders of the preferred shares of any series, or any other class ranking prior to
the common shares. There are no pre-emptive or conversion rights, and the common shares are not
subject to redemption. All common shares currently outstanding and to be outstanding upon exercise of
outstanding options are, or will be, fully paid and non-assessable.
Ratings
Our current long-term debt ratings are A(low) Under Review – Developing by Dominion Bond Rating
Service Limited; A3 with a stable trend by Moody’s Investors Service, Inc; and A-, with a stable trend by
Standard & Poor’s Rating Services, a division of the McGraw-Hill Companies, Inc.
Dominion Bond Rating Service’s ("DBRS") credit ratings are on a long-term debt rating scale that ranges
from AAA to D, which represents the range from highest to lowest quality of such securities rated. A
rating of A (low) by DBRS is the third highest of nine categories and is assigned to debt securities
considered to be of satisfactory credit quality. Protection of interest and principal is still substantial, but
the degree of strength is less than with AA rated entities. Entities in the A category may be more
susceptible to adverse economic conditions and have greater cyclical tendencies than higher rated
companies. The assignment of a "(high)" or "(low)" modifier within each rating category indicates relative
standing within such category. The "high" and "low" grades are not used for the AAA category.
Moody’s credit ratings are on a long-term debt rating scale that ranges from AAA to C, which represents
the range from highest to lowest quality of such securities rated. A rating of A3 by Moody’s is the third
41
highest of nine categories and is assigned to debt securities which are considered upper-medium grade
obligations and are subject to low credit risk. Moody’s appends numerical modifiers 1, 2 or 3 to each
generic rating classification. The modifier 1 indicates that the issue ranks in the higher end of its generic
rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue
ranks in the lower end of its generic rating category.
Standard and Poor’s ("S&P") credit ratings are on a long-term debt rating scale that ranges from AAA to
D, which represents the range from highest to lowest quality of such securities rated. A rating of A- by
S&P is the third highest of eleven categories and indicates that the obligor is somewhat more susceptible
to adverse effects of changes in circumstances and economic conditions than obligors in the higher-rated
categories. However, the obligor’s capacity to meet its financial commitment on the obligation is still
strong. The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing
within a particular rating category.
DBRS’s commercial paper credit ratings are on a short-term debt rating scale that ranges from R-1(high)
to D, which represent the range from highest to lowest quality of such securities rated. A rating of R1(low) by DBRS is the third highest of ten categories and is assigned to debt securities considered to be
of satisfactory credit quality. The overall strength and outlook for key liquidity, debt, and profitability ratios
is not normally as favourable as with higher rating categories, but these considerations are still
respectable, and any qualifying negative factors that exist are considered manageable, and the entity is
normally of sufficient size to have some influence in its industry.
The credit ratings accorded to the notes by the rating agencies are not recommendations to purchase,
hold or sell the notes inasmuch as such ratings do not comment as to the market price or suitability for a
particular investor. Any rating may not remain in effect for any given period of time or may be revised or
withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.
MARKET FOR OUR SECURITIES
Our common shares are listed on the Toronto Stock Exchange in Canada, and on the New York Stock
Exchange in the United States.
Price Range and Trading Volume of Common Shares
Toronto Stock Exchange
2007
January
February
March
April
May
June
July
August
September
October
November
December
Price Range ($Cdn)
High
92.85
88.65
90.00
94.20
96.81
99.70
100.67
97.74
101.55
104.15
108.00
109.47
Low
81.50
82.29
79.66
87.58
88.39
91.10
93.23
88.72
92.14
91.25
94.59
94.89
Trading Volume
(000’s)
43,938
30,930
34,616
27,825
29,160
30,799
31,184
31,945
36,572
42,114
33,919
24,200
42
New York Stock Exchange
2007
Price Range ($US)
January
February
March
April
May
June
July
August
September
October
November
December
High
77.35
75.37
77.79
82.89
89.43
93.52
96.41
92.44
100.11
109.49
117.98
111.31
Low
69.39
70.25
67.78
75.71
79.81
85.59
87.45
82.37
88.83
91.40
94.56
94.70
Trading Volume
(000’s)
43,617
25,738
26,717
22,857
25,577
21,554
22,516
21,372
20,197
24,598
20,548
13,011
DIRECTORS AND EXECUTIVE OFFICERS
Directors
The following individuals are directors of Suncor.
Name and Municipality
of Residence
Mel E. Benson (3)(4)
Calgary, Alberta
Brian A. Canfield
Point Roberts,
Washington
(1)(2)
Bryan P. Davies (3)(4)
Toronto, Ontario
Period Served
and Independence
Principle Occupations During Past Five Years
Director since 2000
Independent
Mel Benson is president of Mel E. Benson Management Services
Inc., an international management consulting firm based in
Calgary, Alberta. In 2000 Mr. Benson retired from a major
international oil company. Mr. Benson is a partner in Kanetax
Energy Inc., Tenax Energy Inc. and a director of Winalta Homes
Inc. He is active with several charitable organizations including
Hull Family Services and the Canadian Aboriginal Professional
Association. He is also a member of the Board of Governors for
the Northern Alberta Institute of Technology and the National
Aboriginal Economic Development Board.
Director since 1995
Independent
Brian Canfield is the chairman of TELUS Corporation, a
telecommunications company. Mr. Canfield is also a director and
chairman of the governance committee of the Canadian Public
Accountability Board. Mr. Canfield is a member of the Order of
Canada, a member of the Order of British Columbia, and a fellow
of the Institute of Corporate Directors.
Director 1991 to 1996
and since 2000
Independent
Bryan Davies is chairman of the Canada Deposit Insurance
Corporation. He is also a director of the General Insurance
Statistical Agency and is past superintendent of the Financial
Services Commission of Ontario. Prior to that, he was senior vice
president, regulatory affairs with the Royal Bank Financial
Group. Mr. Davies is also active with a number of not-for-profit
charitable organizations.
43
Name and Municipality
of Residence
Brian A. Felesky (1)(4)
Calgary, Alberta
Period Served
and Independence
Director since 2002
Independent
John T. Ferguson(2)(3)
Edmonton, Alberta
Director since 1995
Independent
John Ferguson is founder and chairman of the board of
Princeton Developments Ltd. and Princeton Ventures Ltd. Mr.
Ferguson is also a director of Fountain Tire Ltd., the Royal Bank
of Canada and Strategy Summit Ltd. In addition, he is a director
of the C.D. Howe Institute, the Alberta Bone and Joint Institute,
an advisory member of the Canadian Institute for Advanced
Research and chancellor emeritus and chairman emeritus of the
University of Alberta. Mr. Ferguson is also a fellow of the Alberta
Institute of Chartered Accountants.
W. Douglas Ford(1)(2)
Bonita Springs, Florida
Director since 2004
Independent
W. Douglas Ford was chief executive, refining and marketing for
BP p.l.c. from 1998 to 2002 and was responsible for the refining,
marketing and transportation network of the company as well as
the aviation fuels business, the marine business and BP
shipping. Mr. Ford currently serves as a director of USG
Corporation and Air Products and Chemicals, Inc. He is also a
member of the board of trustees of the University of Notre Dame.
Richard L. George
Calgary, Alberta
Director since 1991
Non-independent,
management
Richard George is the president and chief executive officer of
Suncor Energy Inc. Mr. George is also a director of the U.S.
offshore and onshore drilling company Transocean. In 2006, he
was selected to serve as a member of the North American
Competitiveness Council. In 2007, he became a member of the
Calgary Committee to End Homelessness and is currently chair
of the 2008 Governor General’s Canadian Leadership
Conference. Mr. George was named a member of the Order of
Canada in 2007.
Director since 1998
Independent
John Huff is chairman of Oceaneering International Inc., an oil
field services company. He is also a director of BJ Services
Company, KBR and Rowan Companies Inc. Mr. Huff is a
member of the National Petroleum Council, the Houston
Museum of Natural Science and St. Luke’s Episcopal Hospital
System in Houston.
Director since 1995
Independent
Ann McCaig is actively involved with charitable and community
activities. She is past co-chair of the Alberta Children’s Hospital
Foundation which raised $52 million for the new state-of-the-art
pediatric facility in Calgary. She is currently chair of the Alberta
Adolescent Recovery Centre, a trustee of the Killam Estate, chair
of the Calgary Health Trust, a director of the Calgary Stampede
Foundation and honourary chair of the Alberta Bone and Joint
Institute. She is also chancellor emeritus of the University of
Calgary and a member of the Order of Canada.
(2)(3)
John R. Huff
Houston, Texas
(3)(4)
M. Ann McCaig
Calgary, Alberta
Principle Occupations During Past Five Years
Brian Felesky is counsel to the law firm of Felesky Flynn LLP in
Calgary, Alberta. Mr. Felesky also serves as a director on the
board and is chair of the audit committee of Epcor Power LP. He
is also a member of the board of Precision Drilling Trust and
Resin Systems Inc. Mr. Felesky is actively involved in not-forprofit and charitable organizations. He is the co-chair of
Homefront on Domestic Violence, vice chair of the Canada West
Foundation, member of the senate of Athol Murray College of
Notre Dame and board member of the Calgary Stampede
Foundation. Mr. Felesky is a Queen’s Counsel and member of
the Order of Canada.
44
Name and Municipality
of Residence
Michael W. O’Brien(1)(2)
Canmore, Alberta
Period Served
and Independence
Director since 2002
Independent
Eira M. Thomas (1)(4)
West Vancouver, British
Columbia
Director since 2006
Independent
Principle Occupations During Past Five Years
Michael O’Brien served as executive vice president, corporate
development, and chief financial officer of Suncor Energy Inc.
before retiring in 2002. Mr. O’Brien serves on the board of Shaw
Communications Inc. and is an advisor to CRA International. In
addition, he is past chair of the board of trustees for Nature
Conservancy Canada, past chair of the Canadian Petroleum
Products Institute and past chair of Canada’s Voluntary
Challenge for Global Climate Change.
Eira Thomas has been chief executive officer of Stornoway
Diamond Corporation, a mineral exploration company, since July
2003. Previously, Ms. Thomas was president of Navigator
Exploration Corporation and chief executive officer of Stornoway
Ventures Ltd. She is also a director of Strongbow Exploration
Inc. and Fortress Minerals Corp. In addition, Ms. Thomas is a
director of the University of Toronto (U of T) Alumni Association,
Lassonde Advisory Board of the U of T, Prospectors and
Developers Association of Canada and the Northwest Territories
and Nunavut Chamber of Mines. She also is a member of the U
of T President’s Internal Advisory Council.
(1)
Audit Committee
(2)
Board Policy, Strategy Review & Governance Committee
(3)
Human Resources and Compensation Committee
(4)
Environment, Health & Safety Committee
45
Executive Officers
The following individuals are the executive officers of Suncor.
Office(1)(2)
Name and Municipality of Residence
J. KENNETH ALLEY
Calgary, Alberta
Senior Vice President and Chief Financial Officer
MIKE M. ASHAR
Calgary, Alberta
Executive Vice President, Strategic Growth and Energy Trading
KIRK BAILEY
Fort McMurray, Alberta
Executive Vice President, Oil Sands
DAVID W. BYLER
Cochrane, Alberta
Executive Vice President, Natural Gas and Renewable
Energy
RICHARD L. GEORGE
Calgary, Alberta
President and Chief Executive Officer
TERRENCE J. HOPWOOD
Calgary, Alberta
Senior Vice President and General Counsel
SUE LEE
Calgary, Alberta
Senior Vice President, Human Resources and
Communications
KEVIN D. NABHOLZ
Calgary, Alberta
Executive Vice President, Major Projects
THOMAS L. RYLEY
Toronto, Ontario
Executive Vice President, Refining and Marketing
JAY THORNTON
Calgary, Alberta
Senior Vice President, Business Integration
STEVEN W. WILLIAMS
Calgary, Alberta
Chief Operating Officer
Note:
(1) Offices shown are positions held by the officers in relation to businesses of Suncor Energy Inc. and its
subsidiaries. On a legal entity basis, Mr. Ashar is president of Suncor Energy Marketing Inc. and Mr. Ryley is
president of Suncor Energy Products Inc., each of which are Suncor’s Canada-based downstream subsidiaries;
and Mr. Nabholz, Ms. Lee and Mr. Thornton are officers of Suncor Energy Services Inc., which provides major
projects management, human resources and communication, business integration and other shared services to
the Suncor group of companies.
(2) This information reflects the positions of officers as at December 31, 2007.
All of the foregoing executive officers of the Company have, for the past five years, been actively
engaged as executives or employees of Suncor or its affiliates.
The percentage of Common Shares of Suncor owned beneficially, directly or indirectly, or over which
control or direction is exercised by Suncor's directors and executive officers, as a group, is less than 1%.
Additional Disclosure for Directors and Executive Officers
To the best of our knowledge, having made due inquiry, we confirm that, as at the date hereof:
(i)
in the last ten years, no director or executive officer of Suncor is or has been a director or officer
of another issuer that, while that person was acting in that capacity:
46
(ii)
(a)
was the subject of a cease trade or similar order, or an order that denied the relevant
issuer access to any exemption under Canadian securities legislation for a period of more
than 30 consecutive days;
(b)
was subject to an event that resulted, after the director or executive officer ceased to be a
director or executive officer, in the company being the subject of a cease trade or similar
order or an order that denied the relevant company access to any exemption under
securities legislation, for a period of more than 30 consecutive days; or
(c)
became bankrupt or made a proposal under any legislation relating to bankruptcy or
insolvency or was subject to or instituted any proceedings, arrangement or compromise
with creditors or had a receiver, receiver manager or trustee appointed to hold its assets,
other than Mr. Ford, a director of Suncor who is currently a director of USG Corporation,
which was in bankruptcy protection until June, 2006, and who was also a director of
United Airlines (until February 2006) which was in Chapter 11 bankruptcy protection until
February, 2006.
no director or executive officer of Suncor has:
(a)
been subject to any penalties or sanctions imposed by a court relating to securities
legislation or by a securities regulatory authority or has entered into a settlement
agreement with a securities regulatory authority; or
(b)
has been subject to any other penalties or sanctions imposed by a court or regulatory
body that would likely be considered important to a reasonable investor in making an
investment decision;
(iii)
no director or executive officer of Suncor nor any personal holding company controlled by such
person has become bankrupt, made a proposal under any legislation relating to bankruptcy or
insolvency or become subject to or instituted any proceedings, arrangement or compromise with
creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the
director or executive officer; and
(iv)
no director or executive officer has any direct or indirect material interest in respect of any matter
that has materially affected or will materially affect Suncor or any of its subsidiaries.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
No director, executive officer, or principal holder of Suncor securities or any associate or affiliate of these
persons has, or has had, any material interest in any transaction or any proposed transaction that has
materially affected or will materially affect us or any of our affiliates, within the three most recently
completed financial years or during the current financial year.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for our common shares is Computershare Trust Company of Canada at
its principal offices in Calgary, Montreal, Toronto and Vancouver and Computershare Trust Company Inc.
in Denver, Colorado.
47
INTERESTS OF EXPERTS
As at the date hereof the designated professionals of GLJ Petroleum Consultants Ltd., as a group,
beneficially owned, directly or indirectly, less than 1% of our outstanding securities, including the
securities of our associates and affiliates.
FEES PAID TO AUDITORS
Fees Paid to Auditors
Fees payable to PricewaterhouseCoopers LLP in 2006 and 2007 are detailed below.
($)
Audit fees
Audit-related fees
Tax fees
All other fees
Total
(1)
2007
1 440 000
448 000
2 000
–
1 890 000
2006(1)
1 719 000
295 000
–
3 000
2 017 000
Certain prior period comparative figures have been reclassified to conform to current period presentation.
The nature of each category of fees is described below.
Audit Fees
Audit fees were paid for professional services rendered by the auditors for the audit of Suncor’s annual
financial statements or services provided in connection with statutory and regulatory filings or
engagements.
Audit-related Fees
Audit-related fees were paid for professional services rendered by the auditors for preparation of reports
on specified procedures as they relate to joint venture audits, attest services not required by statute or
regulation, and membership fees levied by the Canadian Public Accountability Board.
Tax Fees
Tax fees were paid for international tax planning, advice and compliance.
All Other Fees
Fees disclosed under “All Other Fees” were paid for subscriptions to auditor-provided and supported
tools.
None of the services described under the captions “Audit-related Fees”, “Tax Fees” and “All Other Fees”
were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
Audit Committee Pre-Approval Policies for Non Audit Services
Our Audit Committee has considered whether the provision of services other than audit services is
compatible with maintaining the auditors’ independence and has a policy governing the provision of these
services. A copy of our policy relating to Audit Committee approval of fees paid to our auditors, in
compliance with the Sarbanes Oxley Act of 2002, is attached as Schedule "A" to this AIF.
Audit Committee Charter
The Audit Committee Charter is attached as Schedule “B” to this AIF.
48
Composition of the Audit Committee
The Audit Committee is comprised of Mr. Canfield (Chairman), Mr. Felesky, Mr. Ford, Mr. O’Brien and
Ms. Thomas. All members are independent and financially literate. The education and expertise of each
member is described under the heading “Directors and Executive Officers”.
For the purpose of making appointments to the Company’s Audit Committee, and in addition to the
independence requirements, all directors nominated to the Audit Committee must meet the test of
financial literacy as determined in the judgment of the board of directors. Also, at least one director so
nominated must meet the test of financial expert as determined in the judgment of the board of directors.
The designated financial expert on the Audit Committee is Michael W. O'Brien.
Financial Literacy
Financial literacy can be generally defined as the ability to read and understand a balance sheet, an
income statement and a cash flow statement. In assessing a potential appointee’s level of financial
literacy, the board of directors must evaluate the totality of the individual’s education and experience
including:
•
The level of the person’s accounting or financial education, including whether the person has
earned an advanced degree in finance or accounting;
•
Whether the person is a professional accountant, or the equivalent, in good standing, and the
length of time that the person actively has practised as a professional accountant, or the
equivalent;
•
Whether the person is certified or otherwise identified as having accounting or financial
experience by a recognized private body that establishes and administers standards in respect of
such expertise, whether that person is in good standing with the recognized private body, and the
length of time that the person has been actively certified or identified as having this expertise;
•
Whether the person has served as a principal financial officer, controller or principal accounting
officer of a corporation that, at the time the person held such position, was required to file reports
pursuant to securities laws, and if so, for how long;
•
The person’s specific duties while serving as a public accountant, auditor, principal financial
officer, controller, principal accounting officer or position involving the performance of similar
functions;
•
The person’s level of familiarity and experience with all applicable laws and regulations regarding
the preparation of financial statements that must be included in reports filed under securities laws;
•
The level and amount of the person’s direct experience reviewing, preparing, auditing or
analyzing financial statements that must be included in reports filed under provisions of securities
laws;
•
The person’s past or current membership on one or more audit committees of companies that, at
the time the person held such membership, were required to file reports pursuant to provisions of
securities laws;
•
The person’s level of familiarity and experience with the use and analysis of financial statements
of public companies; and
•
Whether the person has any other relevant qualifications or experience that would assist him or
her in understanding and evaluating the corporation’s financial statements and other financial
information and to make knowledgeable and thorough inquiries whether:
49
•
The financial statements fairly present the financial condition, results of operations and cash
flows of the corporation in accordance with generally accepted accounting principles; and
•
The financial statements and other financial information, taken together, fairly present the
financial condition, results of operations and cash flows of the corporation.
Audit Committee Financial Expert
An “Audit Committee Financial Expert” means a person who, in the judgment of the corporation’s board of
directors, has the following attributes:
a.
an understanding of Canadian generally accepted accounting principles and financial statements;
b.
the ability to assess the general application of such principles in connection with the accounting
for estimates, accruals, and reserves;
c.
experience preparing, auditing or analyzing or evaluating financial statements that present a
breadth and level of complexity of accounting issues that are generally comparable to the breadth
and complexity of issues that can reasonably be expected to be raised by Suncor’s financial
statements, or experience actively supervising one or more persons engaged in such activities;
d.
an understanding of internal controls and procedures for financial reporting; and
e.
an understanding of audit committee functions.
A person shall have acquired the attributes referred to in items (a) through (e) inclusive above through:
a.
education and experience as a principal financial officer, principal accounting officer, controller,
public accountant or auditor or experience in one or more positions that involve the performance
of similar functions;
b.
experience actively supervising a principal financial officer, principal accounting officer, controller,
public accountant, auditor or person performing similar functions;
c.
experience overseeing or assessing the performance of companies or public accountants with
respect to the preparation, auditing or evaluation of financial statements; or
d.
other relevant experience.
RELIANCE ON EXEMPTIVE RELIEF
We are reporting our reserves data in accordance with, and are relying on, the terms of the following
MRRS Decision Document: In the Matter of the Securities Legislation of Alberta, British Columbia,
Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia, Newfoundland and Labrador, Yukon, Northwest
Territories and Nunavut AND In the Matter of The Mutual Reliance Review System for Exemptive Relief
Applications AND In the Matter of Suncor Energy Inc., December 22, 2003 (the "Decision Document").
Our reserves data consists of the following:
•
net proved working interest oil and gas reserve quantities relating to oil and gas operations, other
than mining, estimated as at December 31, 2007, using constant dollar cost and pricing assumptions
as of a point in time, namely December 31, 2007, and the related standardized measure;
•
gross and net proved and probable working interest oil reserve quantities relating to surface mineable
oil sands operations estimated as at December 31, 2007; and
50
•
gross and net proved and probable working interest oil and gas reserve quantities relating to Firebag
in-situ leases, estimated as at December 31, 2007, using constant dollar cost and pricing
assumptions, generally intended to represent a normalized annual average for the year in accordance
with CSA Staff Notice 51-315.
Our estimates of reserves and related standardized measure of discounted future net cash flows (the
"standardized measure") were evaluated or reviewed in accordance with the standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") modified to the extent necessary to
reflect the terminology and standards of US disclosure requirements, including:
•
the information required by the United States Financial Accounting Standards Board, including
Financial Accounting Standard No. 69;
•
the information required by SEC Industry Guide 2 Disclosure of Oil and Gas Operations, as amended
from time to time; and
•
certain other information required in accordance with US disclosure practices.
If we had been reporting our reserves data in accordance with NI 51-101 and had not been relying on the
terms of the Decision Document, we would have been required to report the following:
•
proved and probable working interest oil and gas reserve quantities relating to oil and gas operations,
gross and net, using forecast prices and costs for each of proved developed producing reserves,
proved developed non-producing reserves, proved undeveloped reserves, proved reserves (in total),
probable reserves (in total) and proved plus probable reserves (in total); and
•
future net revenue attributable to the reserves categories referred to above, estimated using forecast
prices and costs, before and after deducting future income tax expenses, calculated without discount
and using discount rates of 5%, 10%, 15% and 20%.
LEGAL PROCEEDINGS
There are no legal proceedings to which we are a party or of which any of our property is the subject, nor
are there any proceedings known by us to be contemplated that involves a claim for damages exceeding
ten percent of our current assets.
ADDITIONAL INFORMATION
Additional information, including directors' and officers' remuneration and indebtedness, principal holders
of our securities, options to purchase securities and interests of insiders in material transactions, where
applicable, is contained in our most recent management proxy circular for our most recent annual
meeting of our shareholders that involved the election of directors. Additional financial information is
provided in our 2007 Consolidated Financial Statements.
Further information about Suncor, filed with Canadian securities commissions and the United States
Securities and Exchange Commission (SEC), including periodic quarterly and annual reports and the
Annual Information Form (AIF/40-F) is available online at www.sedar.com and www.sec.gov. In addition,
our Standards of Business Conduct Code is available online at www.suncor.com. Information contained
in or otherwise accessible through our website does not form part of this AIF, and is not incorporated into
the AIF by reference.
51
SCHEDULE "A"
***Approved and Accepted April 28, 2004***
SUNCOR ENERGY INC.
POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT
AND NON-AUDIT SERVICES
Pursuant to the Sarbanes-Oxley Act of 2002 and Multilateral Instrument 52-110, the Securities
and Exchange Commission and the Ontario Securities Commission respectively has adopted
final rules relating to audit committees and auditor independence. These rules require the Audit
Committee of Suncor Energy Inc (“Suncor”) to be responsible for the appointment, compensation,
retention and oversight of the work of its independent auditor. The Audit Committee must also
pre-approve any audit and non-audit services performed by the independent auditor or such
services must be entered into pursuant to pre-approval policies and procedures established by
the Audit Committee pursuant to this policy.
I.
STATEMENT OF POLICY
The Audit Committee has adopted this Policy and Procedures for Pre-Approval of Audit and NonAudit Services (the “Policy”), which sets forth the procedures and the conditions pursuant to
which services proposed to be performed by the independent auditor will be pre-approved. The
procedures outlined in this Policy are applicable to all Audit, Audit-Related, Tax Services and All
Other Services provided by the independent auditor.
II.
RESPONSIBILITY
Responsibility for the implementation of this Policy rests with the Audit Committee. The Audit
Committee delegates its responsibility for administration of this policy to management. The Audit
Committee shall not delegate its responsibilities to pre-approve services performed by the
independent auditor to management.
III.
DEFINITIONS
For the purpose of these policies and procedures and any pre-approvals:
a)
“Audit services” include services that are a necessary part of the annual audit process
and any activity that is a necessary procedure used by the auditor in reaching an opinion
on the financial statements as is required under generally accepted auditing standards
(“GAAS”), including technical reviews to reach audit judgment on accounting standards;
The term “audit services” is broader than those services strictly required to perform an
audit pursuant to GAAS and include such services as:
i)
the issuance of comfort letters and consents in connections with offerings of
securities;
ii)
the performance of domestic and foreign statutory audits;
iii)
Attest services required by statute or regulation;
iv)
Internal control reviews; and
v)
Assistance with and review of documents filed with the Canadian Securities
administrators, the Securities and Exchange Commission and other regulators
1
having jurisdiction over Suncor and its subsidiaries, and responding to comments
from such regulators;
b)
“Audit-related services” are assurance (e.g. due diligence services) and related services
traditionally performed by the external auditors and that are reasonably related to the
performance of the audit or review of financial statements and not categorized under
“audit fees” for disclosure purposes.
“Audit-related services” include:
i)
employee benefit plan audits, including audits of employee pension plans;
ii)
due diligence related to mergers and acquisitions;
iii)
consultations and audits in connection with acquisitions, including evaluating the
accounting treatment for proposed transactions;
iv)
internal control reviews;
v)
attest services not required by statute or regulation; and
vi)
consultations regarding financial accounting and reporting standards;
Non-financial operational audits are not “audit-related” services;
c)
“Tax services” include but are not limited to services related to the preparation of
corporate and/or personal tax filings, tax due diligence as it pertains to mergers,
acquisitions and/or divestitures and tax planning;
d)
“All other services” consist of any other work that is neither an Audit service, nor an AuditRelated service nor a Tax service, the provision of which by the independent auditor is
not expressly prohibited by Rule 2-01(c)(7) of Regulation S-X under the Securities and
Exchange Act of 1934, as amended. (See Appendix A for a summary of the prohibited
services.)
IV.
GENERAL POLICY
The following general policy applies to all services provided by the independent auditor:
•
All services to be provided by the independent auditor will require specific pre-approval
by the Audit Committee. The Audit Committee will not approve engaging the
independent auditor for services which can reasonably be classified as “tax services” or
“all other services” unless a compelling business case can be made for retaining the
independent auditor instead of another service provider.
•
The Audit Committee will not provide pre-approval for services to be provided in excess
of twelve months from the date of the pre-approval, unless the Audit Committee
specifically provides for a different period.
•
The Audit Committee has delegated authority to pre-approve services with an estimated
cost not exceeding $100,000 in accordance with this Policy to the Chairman of the Audit
Committee. The delegate member of the Audit Committee must report any pre-approval
decision to the Audit Committee at its next meeting.
•
The Chairman of the Audit Committee may delegate his authority to pre-approve services
to another sitting member of the Audit Committee provided that the recipient has also
2
been delegated the authority to act as Chairman of the Audit Committee in the
Chairman’s absence. A resolution of the Audit Committee is required to evidence the
Chairman’s delegation of authority to another Audit Committee member under this policy.
•
The Audit Committee will, from time to time, but no less than annually, review and preapprove the services that may be provided by the independent auditor.
•
The Audit Committee must establish pre-approval fee levels for services provided by the
independent auditor on an annual basis. On at least a quarterly basis, the Audit
Committee will be provided with a detailed summary of fees paid to the independent
auditor and the nature of the services provided and a forecast of fees and services that
are expected to be provided during the remainder of the fiscal year.
•
The Audit Committee will not approve engaging the independent auditor to provide any
prohibited non-audit services as set forth in Appendix A.
•
The Audit Committee shall evidence their pre-approval for services to be provided by the
independent auditor as follows:
•
•
a)
In situations where the Chairman of the Audit Committee pre-approves work
under his delegation of authority, the Chairman will evidence his pre-approval by
signing and dating the pre-approval request form, attached as Appendix B. If it is
not practicable for the Chairman to complete the form and transmit it to the
Company prior to engagement of the independent audit, the Chairman may
provide verbal or email approval of the engagement, followed up by completion
of the request form at the first practical opportunity.
b)
In all other situations, a resolution of the Audit Committee is required.
All audit and non-audit services to be provided by the independent auditors shall be
provided pursuant to an engagement letter that shall:
a)
be in writing and signed by the auditors
b)
specify the particular services to be provided
c)
specify the period in which the services will be performed
d)
specify the estimated total fees to be paid, which shall not exceed the estimated
total fees approved by the Audit Committee pursuant to these procedures, prior
to application of the 10% overrun.
e)
include a confirmation by the auditors that the services are not within a category
of services the provision of which would impair their independence under
applicable law and Canadian and U.S. generally accepted accounting standards.
The Audit Committee pre-approval permits an overrun of fees pertaining to a particular
engagement of no greater than 10% of the estimate identified in the associated
engagement letter. The intent of the overrun authorization is to ensure on an interim
basis only, that services can continue pending a review of the fee estimate and if
required, further Audit Committee approval of the overrun. If an overrun is expected to
exceed the 10% threshold, as soon as the overrun is identified, the Audit Committee or
its designate must be notified and an additional pre-approval obtained prior to the
engagement continuing.
3
V.
RESPONSIBILITIES OF EXTERNAL AUDITORS
To support the independence process, the independent auditors will:
a)
Confirm in each engagement letter that performance of the work will not impair
independence;
b)
Satisfy the Audit Committee that they have in place comprehensive internal policies and
processes to ensure adherence, world-wide, to independence requirements, including
robust monitoring and communications;
c)
Provide communication and confirmation to the Audit Committee regarding independence
on at least a quarterly basis;
d)
Maintain registration by the Canadian Public Accountability Board and the U.S. Public
Company Accounting Oversight Board;
e)
Review their partner rotation plan and advise the Audit Committee on an annual basis.
In addition, the external auditors will:
a)
Provide regular, detailed fee reporting including balances in the “Work in Progress”
account;
b)
Monitor fees and notify the Audit Committee as soon as a potential overrun is identified.
VI.
DISCLOSURES
Suncor will, as required by applicable law, annually disclose its pre-approval policies and
procedures, and will provide the required disclosure concerning the amounts of audit fees, auditrelated fees, tax fees and all other fees paid to its outside auditors in its filings with the SEC.
*
*
*
4
Appendix A
Prohibited Non-Audit Services
An external auditor is not independent if, at any point during the audit and professional engagement
period, the auditor provides the following non-audit services to an audit client.
Bookkeeping or other services related to the accounting records or financial statements of the audit client.
Any service, unless it is reasonable to conclude that the results of these services will not be subject to
audit procedures during an audit of Suncor’s financial statements, including:
•
•
•
Maintaining or preparing the audit client’s accounting records;
Preparing Suncor’s financial statements that are filed with the Securities and Exchange
Commission (“SEC”) or that form the basis of financial statements filed with the SEC; or
Preparing or originating source data underlying Suncor’s financial statements.
Financial information systems design and implementation. Any service, unless it is reasonable to
conclude that the results of these services will not be subject to audit procedures during an audit of
Suncor’s financial statements, including:
•
•
Directly or indirectly operating, or supervising the operation of, Suncor’s information system or
managing Suncor’s local area network; or
Designing or implementing a hardware or software system that aggregates source data
underlying the financial statements or generates information that is significant to Suncor’s
financial statements or other financial information systems taken as a whole.
Appraisal or valuation services, fairness opinions or contribution-in-kind reports. Any appraisal service,
valuation service or any service involving a fairness opinion or contribution-in-kind report for Suncor,
unless it is reasonable to conclude that the results of these services will not be subject to audit
procedures during an audit of Suncor’s financial statements.
Actuarial services. Any actuarially-oriented advisory service involving the determination of amounts
recorded in the financial statements and related accounts for Suncor other than assisting Suncor in
understanding the methods, models, assumptions, and inputs used in computing an amount, unless it is
reasonable to conclude that the results of these services will not be subject to audit procedures during an
audit of Suncor’s financial statements.
Internal audit outsourcing services. Any internal audit service that has been outsourced by Suncor that
relates to Suncor’s internal accounting controls, financial systems, or financial statements, unless it is
reasonable to conclude that the result of these services will not be subject to audit procedures during an
audit of Suncor’s financial statements.
Management functions. Acting, temporarily or permanently, as a director, officer, or employee of Suncor,
or performing any decision-making, supervisory, or ongoing monitoring function for Suncor.
Human resources.
•
•
•
•
•
Searching for or seeking out prospective candidates for managerial, executive, or director
positions;
Engaging in psychological testing, or other formal testing or evaluation programs;
Undertaking reference checks of prospective candidates for an executive or director position;
Acting as a negotiator on Suncor’s behalf, such as determining position, status or title,
compensation, fringe benefits, or other conditions of employment; or
Recommending, or advising Suncor to hire a specific candidate for a specific job (except that an
accounting firm may, upon request by Suncor, interview candidates and advise Suncor on the
candidate’s competence for financial accounting, administrative, or control positions.)
1
Broker-dealer, investment adviser or investment banking services. Acting as a broker-dealer (registered
or unregistered), promoter, or underwriter, on behalf of Suncor, making investment decisions on behalf of
Suncor or otherwise having discretionary authority over Suncor’s investments, executing a transaction to
buy or sell Suncor’s investment, or having custody of Suncor’s assets, such as taking temporary
possession of securities purchased by Suncor.
Legal services. Providing any service to Suncor that, under circumstances in which the service is
provided, could be provided only by someone licensed, admitted, or otherwise qualified to practice law in
the jurisdiction in which the service is prohibited.
Expert services unrelated to the audit. Providing an expert opinion or other expert service for Suncor, or
Suncor’s legal representative, for the purpose of advocating Suncor’s interest in litigation or in a
regulatory or administrative proceeding or investigation. In any litigation or regulatory or administrative
proceeding or investigation, an accountant’s independence shall not be deemed to be impaired if the
accountant provides factual accounts, including testimony, of work performed or explains the positions
taken or conclusions reached during the performance of any service provided by the accountant for
Suncor.
2
Appendix B
Pre-approval Request Form
NATURE OF WORK
ESTIMATED FEES
(Cdn $)
Total
Date
Signature
1
SCHEDULE "B"
AUDIT COMMITTEE CHARTER
The Audit Committee
The by-laws of Suncor Energy Inc. provide that the Board of Directors may establish Board committees to
whom certain duties may be delegated by the Board. The Board has established, among others, the
Audit Committee, and has approved this mandate, which sets out the objectives, functions and
responsibilities of the Audit Committee.
Objectives
The Audit Committee assists the Board of Directors by:
•
monitoring the effectiveness and integrity of the Corporation's financial reporting systems,
management information systems and internal control systems, and by monitoring financial reports
and other financial matters.
•
selecting, monitoring and reviewing the independence and effectiveness of, and where appropriate
replacing, subject to shareholder approval as required by law, external auditors, and ensuring that
external auditors are ultimately accountable to the Board of Directors and to the shareholders of the
Corporation.
•
Reviewing the effectiveness of the internal auditors; and
•
approving on behalf of the Board of Directors certain financial matters as delegated by the Board,
include the matters outlined in this mandate.
The Committee does not have decision-making authority, except in the very limited circumstances
described herein or where and to the extent that such authority is expressly delegated by the Board of
Directors. The Committee conveys its findings and recommendations to the Board of Directors for
consideration and, where required, decision by the Board of Directors.
Constitution
The Terms of Reference of Suncor’s Board of Directors set out requirements for the composition of Board
Committees and the qualifications for Committee membership, and specify that the chair and membership
of the Committees are determined annually by the Board. As required by Suncor’s by-laws, unless
otherwise determined by resolution of the board of directors, a majority of the members of a committee
constitute a quorum for meetings of committees, and in all other respects, each committee determines its
own rules of procedure.
Functions and Responsibilities
The Committee has the following functions and responsibilities:
Internal Controls
1.
Enquire as to the adequacy of the Corporation's system of internal controls, and review the
evaluation of internal controls by internal auditors, and the evaluation of financial and internal
controls by external auditors.
2.
Review management's monitoring of compliance with the Corporation's Code of Business
Conduct.
1
3.
Establish procedures for the confidential submission by employees of complaints relating to any
concerns with accounting, internal control, auditing or Standards of Business Conduct Code
matters, and periodically review a summary of complaints and their related resolution.
4.
Review the findings of any significant examination by regulatory agencies concerning the
Corporation's financial matters.
5.
Periodically review management’s governance processes for information technology resources,
to assess their effectiveness in addressing the integrity, the protection and the security of the
Corporation's electronic information systems and records.
6.
Review the management practices in effect over officers' expenses and perquisites.
External and Internal Auditors
7.
Evaluate the performance of the external auditors and initiate and approve the engagement or
termination of the external auditors, subject to shareholder approval as required by applicable
law.
8.
Review the audit scope and approach of the external auditors, and approve their terms of
engagement and fees.
9.
Review any relationships or services that may impact the objectivity and independence of the
external auditor, including annual review of the auditor’s written statement of all relationships
between the auditor (including its affiliates) and the Corporation; review and approve all
engagements for non-audit services to be provided by external auditors or their affiliates.
10.
Review the external auditor’s quality control procedures including any material issues raised by
the most recent quality control review or peer review and any issues raised by a government
authority or professional authority investigation of the external auditor, providing details on actions
taken by the firm to address such issues.
11.
Review and approve the appointment or termination of the Director, Internal Audit, and annually
review a summary of the remuneration and performance of the Director, Internal Audit.
12.
Review the Internal Audit Department Charter, and the plans, activities, organisational structure
and qualifications of the internal auditors, and monitor the department's performance and
independence.
13.
Provide an open avenue of communication between management, the internal auditors or the
external auditors, and the Board of Directors.
Financial Reporting and other Public Disclosure
14.
Review external auditor's management comment letter and management's responses thereto,
and enquire as to any disagreements between management and external auditors or restrictions
imposed by management on external auditors. Review any unadjusted differences brought to the
attention of management by the external auditor and the resolution of same.
15.
Review with management and external auditors the financial materials and other disclosure
documents referred to in paragraph 16, including any significant financial reporting issues, the
presentation and impact of significant risks and uncertainties, and key estimates and judgements
of management that may be material to financial reporting including alternative treatments and
their impacts.
16.
Review and approve the Corporation's interim consolidated financial statements and
accompanying management’s discussion and analysis (“MD&A”).
Review and make
recommendations to the Board of Directors on approval of the Corporation’s annual audited
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financial statements and MD&A, Annual Information Form and Form 40-F. Review other material
annual and quarterly disclosure documents or regulatory filings containing or accompanying
audited or unaudited financial information.
17.
Review and approve the Corporation’s policy on external communication and disclosure of
material information, including the form and generic content of any quarterly earnings guidance
and of any financial disclosure provided to investment analysts and rating agencies.
18.
Review any change in the Corporation's accounting policies.
19.
Review with legal counsel any legal matters having a significant impact on the financial reports.
Oil and Gas Reserves
20.
Review with reasonable frequency Suncor’s procedures for:
(A) the disclosure in accordance with applicable law of information with respect to Suncor’s oil
and gas activities including procedures for complying with applicable disclosure
requirements;
(B) providing information to the qualified reserves evaluators (“Evaluators”) engaged annually by
Suncor to evaluate Suncor’s reserves data for the purpose of public disclosure of such data
in accordance with applicable law.
21.
Annually approve the appointment and terms of engagement of the company’s Evaluator,
including the qualifications and independence of the Evaluator; Review and approve any
proposed change in the appointment of the Evaluator, and the reasons for such proposed change
including whether there have been disputes between the Evaluator and the Company’s
management.
22.
Annually review Suncor’s reserves data and the report of the Evaluator thereon; Annually review
and make recommendations to the Board of Directors on the approval of (i) the content and filing
by the Company of a statement of reserves data (“Statement”) and report of management and the
directors thereon to be included in or filed with the Statement, and (ii) the filing of the report of the
Evaluator to be included in or filed with the Statement, all in accordance with applicable law.
Risk Management
23.
Periodically review the policies and practices of the Corporation respecting cash management,
financial derivatives, financing, credit, insurance, taxation, commodities trading and related
matters. Oversee the Board's risk management governance model by conducting periodic
reviews with the objective of appropriately reflecting the principal risks of the Corporation's
business in the mandate of the Board and its committees.
Pension Plan
24.
Review the assets, financial performance, funding status, investment strategy and actuarial
reports of the Corporation's pension plan including the terms of engagement of the plan’s actuary
and fund manager.
Security
25.
Review on a summary basis any significant physical security management, IT security or
business recovery risks and strategies to address such risks.
Other Matters
26.
Conduct any independent investigations into any matters which come under its scope of
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responsibilities.
27.
Review any recommended appointees to the office of Chief Financial Officer.
Review and/or approve other financial matters delegated specifically to it by the Board of
Directors.
Reporting to the Board
28.
Report to the Board of Directors on the activities of the Committee with respect to the foregoing
matters as required at each Board meeting and at any other time deemed appropriate by the
Committee or upon request of the Board of Directors.
As adopted by resolution of the Board of Directors.
Revision Dated January 26, 2006
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FORM 51-101F3
REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION
This is the form referred to in item 3 of section 2.1 of National Instrument 51-101 Standards of Disclosure
for Oil and Gas Activities ("NI 51-101"), as amended pursuant to the MRRS Decision Document dated
December 22, 2003, In the Matter of Suncor Energy Inc. (the "Decision Document").
Terms to which a meaning is ascribed in the Decision Document have the same meaning in this form.
Management of Suncor Energy Inc. (the "Company") are responsible for the preparation and disclosure of
information with respect to the Company’s oil and gas and surface mineable oil sands activities in
accordance with securities regulatory requirements. This information includes reserves data, which
consist of the following:
(a)
proved working interest oil and gas reserve quantities relating to oil and gas operations, other
than mining, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions as of
a point in time, namely December 31, 2007, and the related standardized measure;
(b)
proved and probable working interest oil reserve quantities relating to surface mineable oil sands
operations estimated as at December 31, 2007; and
(c)
proved and probable working interest oil and gas reserve quantities relating to Firebag in-situ
leases, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions, generally
intended to represent a normalized annual average for the year in accordance with CSA Staff Notice 51315.
GLJ Petroleum Consultants Ltd., independent qualified reserves evaluators, have evaluated the
Company's reserves data. The report of the independent qualified reserves evaluators will be filed with
securities regulatory authorities concurrently with this report.
The Audit Committee of the board of directors of the Company has
(a)
reviewed the Company’s procedures for providing information to the independent qualified
reserves evaluators;
(b)
met with the independent qualified reserves evaluators to determine whether any restrictions
affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c)
reviewed the reserves data with management and the independent qualified reserves evaluators.
The Audit Committee of the board of directors has reviewed the Company’s procedures for assembling
and reporting other information associated with oil and gas and surface mineable oil sands activities and
has reviewed that information with management. The board of directors has, on the recommendation of
the Audit Committee, approved
(a)
the content and filing with securities regulatory authorities of the reserves data and other oil and
gas and surface mineable oil sands information;
(b)
the filing of the report of the independent qualified reserves evaluators on the reserves data; and
(c)
the content and filing of this report.
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Because the reserves data are based on judgments regarding future events, actual results will vary and
the variations may be material.
"RICHARD L. GEORGE"
RICHARD L. GEORGE
President and Chief Executive Officer
"J. KENNETH ALLEY"
J. KENNETH ALLEY
Senior Vice President and Chief Financial Officer
"JOHN T. FERGUSON"
JOHN T. FERGUSON
Chairman of the Board of Directors
"BRIAN A. CANFIELD"
BRIAN A. CANFIELD
Chairman of the Audit Committee
March 3, 2008
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REPORT ON RESERVES DATA
BY INDEPENDENT QUALIFIED RESERVES
EVALUATOR
Suncor Energy Inc.
P.O. Box 38
112 – 4th Avenue S.W.
Calgary, AB T2P 2V5
To:
The Board of Directors of Suncor Energy Inc.
Re:
Form 51-101F2, as modified in accordance with exemptions from
National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101")
contained in the MRRS Decision Document dated December 22, 2003,
In the Matter of Suncor Energy Inc. (the "Decision Document")
We are providing this report in accordance with the terms of the Decision Document and any capitalized
terms, not otherwise defined in this report, shall have the same meaning as set out in the Decision
Document.
We have evaluated the Company’s reserves data as at December 31, 2007. The reserves data consist of
the following:
Proved working interest oil and gas reserve quantities relating to oil and gas operations, other than
mining, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions as of a
point in time, namely December 31, 2007, and the related standardized measure; proved and probable
working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at
December 31, 2007; and proved and probable working interest oil reserves quantities relating to Firebag
in-situ leases, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions.
The reserves data are the responsibility of the Company’s management. Our responsibility is to express
an opinion on the reserves data based on our evaluation.
We evaluated or reviewed the Company's estimates of reserves and related future net revenue (or, where
applicable, related standardized measure of discounted future net cash flows (the standardized
measure)) in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook
(the "COGE Handbook") modified to the extent necessary to reflect the terminology and standards of the
US Disclosure Requirements.
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Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to
whether the reserves data are free of material misstatement. An evaluation also includes assessing
whether the reserves data are in accordance with principles and definitions presented in the COGE
Handbook, as modified to the extent necessary to reflect the terminology and standards of the US
Disclosure Requirements.
The following table sets forth the estimated standardized measure of future cash flows (before deducting
income taxes) attributed to proved oil and gas reserve quantities not related to mining operations,
estimated using constant prices and costs and calculated using a discount rate of 10 percent, included in
the reserves data of the Company evaluated for the year ended, December 31, 2007:
Preparation Date of
Report
February 11, 2008
Location of Reserves
Canada
Standardized Measure of Future Cash Flows for
Proved Oil and Gas Reserve Quantities (before
income taxes, 10% discount rate)
Evaluated
Reviewed
Total
$1,108 million
(94%)
$75 million
(6%)
$1,183 million
(100%)
In addition, all proved plus probable company gross and net reserves have been evaluated for Suncor’s
oil sands mining properties located in Canada and all reserves and resources have been evaluated or
reviewed for all of Suncor’s oil and gas plus mining operations.
In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are
in accordance with the COGE Handbook, as modified or amended as set out above. We express no
opinion on the reserves data that we reviewed but did not audit or evaluate.
We have no responsibility to update our reports evaluating reserves data of the Company by us for the
year ended December 31, 2007 for events and circumstances occurring after the preparation dates of our
reports.
Reserves are estimates only, and not exact quantities. Because the reserves data are based on
judgments regarding future events, actual results will vary and the variations may be material.
Executed as to our report referred to above:
GLJ PETROLEUM CONSULTANTS LTD.
ORIGINALLY SIGNED BY
Dana B. Laustsen, P. Eng.
Executive Vice-President
Calgary, Alberta, Canada
March 3, 2008
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